June 7, 2013 Executive Secretary Michigan Public Service

Founded in 1852 by Sidney Davy Miller

MICHIGAN: Ann Arbor Detroit Grand Rapids

Howell Kalamazoo Lansing Monroe

Saginaw Troy

New York, NY Pensacola, FL

Washington, DC

CANADA: Windsor, ONSHERRI A. WELLMAN TEL: (517) 483-4954 FAX: (517) 374-6304 E-MAIL: [email protected]

One Michigan Avenue, Suite 900 Lansing, Michigan 48933

TEL: (517) 487-2070 FAX: (517) 374-6304

www.millercanfield.com

POLAND: GdyniaWarsaw Wrocław

June 7, 2013

Ms. Mary Jo Kunkle Executive Secretary Michigan Public Service Commission 6545 Mercantile Way, Suite 7 Lansing, MI 48911 Re: Michigan Gas Utilities Corporation 2014 Rate Case

MPSC Case No. U-17273 Dear Ms. Kunkle: Attached for filing are an Application, draft Notice of Hearing, and supporting Direct Testimony, Exhibits, and Workpapers of Katherine A. De Cramer, Matthew M. Dirksen, Christine M. Phillips, Noreen E. Cleary, Chuck F. Hauska, Brian E. Kage, Michael E. Gerth, Tracy L. Kupsh, Lisa J. Gast, Paul R. Moul, Joylyn C. Hoffman Malueg, David J. Tyler, and John R. Wilde. Also attached is documentation which complies with the Rate Case Filing Requirements established by the Commission’s Orders dated December 23, 2008 and February 20, 2009 issued in Case No. U-15895. Very truly yours, SAW/djk Sherri A. Wellman Enclosures cc with enc: David J. Kyto, PE, CMA

STATE OF MICHIGAN

BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * * In the matter of the application of ) MICHIGAN GAS UTILITIES CORPORATION ) for authority to increase retail natural gas rates. ) Case No. U-17273 )

APPLICATION

MICHIGAN GAS UTILITIES CORPORATION (“MGUC”), requests authority from the

Michigan Public Service Commission (“Commission”) to increase its rates for the sale and

transportation of natural gas, and other relief, and in support thereof respectfully represents

as follows:

INTRODUCTION

1. MGUC is a public utility engaged in the purchase, storage, transportation,

distribution and sale of natural gas to approximately 166,000 customers in 147 communities

in the Southern and Western portions of Michigan’s Lower Peninsula.

2. MGUC is a corporation organized under the laws of the state of Delaware,

with its principal office located at 899 S. Telegraph Road, Monroe, Michigan 48161, and is

authorized to transact business in the state of Michigan. MGUC is a subsidiary of Integrys

Energy Group, Inc. (“Integrys”), which prior to February 21, 2007, was known as WPS

Resources Corporation (“WPSR”). MGUC is a sister utility company to Upper Peninsula

Power Company and Wisconsin Public Service Corporation, both of which are also

regulated by this Commission. MGUC is also a sister utility company to, among others,

Minnesota Energy Resources Corporation, The Peoples Gas Light and Coke Company, and

North Shore Gas Company, none of which is regulated by this Commission. MGUC was

acquired by WPSR from Aquila, Inc. on April 1, 2006 as authorized by the Commission’s

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order in Case No. U-14657. Prior to its acquisition by WPSR, MGUC conducted business

as “Aquila Networks – MGU”.

3. MGUC’s retail natural gas sales and transportation business is subject to the

jurisdiction of the Commission pursuant to 1909 PA 300, as amended, MCL 462.2 et seq.;

1919 PA 419, as amended, MCL 460.51 et seq.; 1939 PA 3, as amended, MCL 460.1 et

seq.; 1982 PA 304, as amended, MCL 460.6h et seq.; 1969 PA 306, as amended, MCL

24.201 et seq.; and the Commission’s Rules of Practice and Procedure, as amended, 1999

AC, R 460.17101 et seq.

4. In its last general rate case for retail natural gas service, Case No. U-15990,

MGUC used a 2010 test year. A settlement was reached and approved by the Commission

in its Order Approving Partial Settlement Agreement dated December 16, 2009. This order

granted rate relief of $3.5 million annually, based on a 10.75% return on common equity,

effective January 1, 2010.

5. MGUC’s rates established in Case No. U-15990 do not reflect the current

costs of providing retail gas service, and MGUC requires further rate relief.

REQUESTED RELIEF

6. For purposes of this case, MGUC has undertaken a complete examination of

its investments, expenses and revenues based on a 2014 test year. Using a 2014 test year,

and a return on common equity of 10.75%, MGUC calculates a rate revenue deficiency of

$8,036,820, or 6.01%. The key factors contributing to the revenue deficiency results

include:

a. The 2012 historic test year indicates that MGUC suffered a revenue deficiency of $6,301,860, which corresponds to a 6.14% return on common equity. This value is well below MGUC’s authorized return on common equity of 10.75% authorized in MGUC’s most recent general rate case proceeding in Case No. U-15990.

b. The cost of upgrades to the MGUC gas transmission and distribution systems,

c. A decrease in margin revenues,

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d. A higher cost of capital;

e. Increased costs associated with filling employee vacancies,

f. Increased costs associated with building maintenance,

g. The cost of engineering analysis on vintage natural gas transmission and

distribution mains,

h. Increased costs of customer service functions, and

i. General inflation.

7. MGUC represents that in order to establish rates for natural gas service

which are just and reasonable, it is essential that the Commission order an increase in

natural gas base rates that will produce additional revenues on an annual basis of

approximately $8,036,820, or 6.01%.

8. MGUC represents that its present return on investment is and will be below

that required by sound regulation; that MGUC’s present natural gas rates and charges, if not

increased, will produce increasingly inadequate natural gas revenues to MGUC and, thus,

are unjust and unreasonable; that rate relief is required to permit MGUC to continue to

achieve its goal of rendering adequate natural gas service to the public; and that rate relief,

effective in the near future, is necessary to protect the rights of MGUC and to prevent it from

being deprived of its property contrary to the Fourteenth Amendment of the Constitution of

the United States of America and contrary to the provisions of the Constitution of 1963 of the

State of Michigan.

RATE DESIGN, TARIFF AND OTHER PROPOSALS

9. MGUC’s proposed rate increases by rate schedule are shown on Schedules

F3.1 and F3.2 of Exhibit A-6 (DJT-1). These rates are designed to recover the revenue

deficiency. Furthermore, MGUC also requests authority from the Commission to continue its

currently authorized revenue decoupling mechanism, as initially authorized in Case No. U-

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15990. This plan helps stabilize MGUC’s revenues from the impacts of the economy,

energy efficiency, and other factors.

10. MGUC also requests the authority from the Commission to continue its

Uncollectible Expense True-Up Mechanism (“UETM”), as ordered in Case No. U-15990.

The UETM helps to stabilize MGUC’s uncollectibles expense. Given the state of the

Michigan economy and the MPSC rules regarding shut-off, continuation of the UETM is

reasonable and necessary.

11. In addition, MGUC proposes revisions to its tariffs to reflect the change in

rates.

IMPLEMENTATION OF RATES

12. In accordance with MCL 460.6a(1), if the Commission has not acted on the

Company’s application within 180 days of the filing, MGUC intends to implement interim

rates for service rendered on and after January 1, 2014, up to the amount of the proposed

annual rate request, through equal percentage increases applied to all rates.

TESTIMONY AND EXHIBITS

13. MGUC is filing herewith written testimonies, exhibits and work papers in

support of the requested rate increase and related approvals requested herein.

14. MGUC represents that the proposals contained in this Application,

testimonies, exhibits and work papers are just, reasonable and in the public interest.

WHEREFORE, Michigan Gas Utilities Corporation requests that this Commission:

A. Set an early hearing date on this Application for rate relief;

B. Find and determine that MGUC’s existing rates and charges are

unreasonably low, inadequate and should be increased;

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C. Authorize MGUC to file and make effective, at the earliest possible date, its

proposed final rates and charges for the sale and transportation of natural gas;

D. Authorize MGUC to continue its revenue decoupling mechanism;

E. Authorize MGUC to continue its Uncollectible Expense True-Up Mechanism;

and

F. Grant MGUC such other and further relief and authorizations as may be

lawful and proper.

Respectfully submitted,

MICHIGAN GAS UTILITIES CORPORATION

Dated: June 7, 2013 By: _______________________________

One of Its Attorneys Sherri A. Wellman (P38989) Paul M. Collins (P69719) MILLER, CANFIELD, PADDOCK and STONE, PLC One Michigan Avenue, Suite 900 Lansing, MI 48933 (517) 487-2070 Attorneys for Michigan Gas Utilities Corporation

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MICHIGAN PUBLIC SERVICE COMMISSION

CASE NO. U-17273 Date: June 7, 2013

GENERAL APPLICATION FOR CHANGE IN GAS UTILITY RATES BEFORE MICHIGAN PUBLIC SERVICE COMMISSION CLASS A & B UTILITIES COMPANY NAME: Michigan Gas Utilities Corporation ADDRESS: 899 S. Telegraph Road, Monroe, Michigan 48161 TELEPHONE: AREA CODE (920) NUMBER 433-1502 COMPANY OFFICIAL TO BE CONTACTED PERTAINING TO RATE CASE MATTERS: David J. Kyto, PE, CMA FILING DATE: June 7, 2013 TITLE OF AUTHORIZED OFFICER: Director - Rate Case Process

* * * COMMISSION ONLY * * *

DATE RECEIVED BY COMMISSION: DOCKET NUMBER ASSIGNED: RECEIVED BY: DATE ACCEPTED: ACCEPTED BY: NOTIFICATION DATE(S): SCHEDULED PRE-HEARING DATE:

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STATE OF MICHIGAN



CERTIFICATION OF DAVID J. KYTO, PE, CMA

David J. Kyto, PE, CMA, Director - Rate Case Process of Integrys Business Support, LLC, states that he has provided the data required pursuant to Rate Case Filing Requirements established by the Commission’s Orders dated December 23, 2008 and February 20, 2009 issued in Case No. U-15895, and pursuant to these requirements, certifies the data so provided.

Dated: June 7, 2013 David J. Kyto, PE, CMA

STATE OF MICHIGAN BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION

* * * * *

NOTICE OF HEARING

FOR THE CUSTOMERS OF MICHIGAN GAS UTILITIES CORPORATION

CASE NO. U-17273

• Michigan Gas Utilities Corporation may increase its retail natural gas rates by $8,036,820 annually, or 6.01%, if the Michigan Public Service Commission approves its request.

• A TYPICAL RESIDENTIAL CUSTOMER WHO USES 88 MCF (THOUSAND CUBIC

FEET) OF NATURAL GAS PER YEAR MAY SEE AN ANNUAL INCREASE OF $28.09, OR ABOUT 4.0%, IF THE REQUESTED RATE RELIEF IS GRANTED.

• The information below describes how a person may participate in this case.

• You may call or write Michigan Gas Utilities Corporation, 899 S. Telegraph Road,

Monroe, Michigan 48161, (734) 457-6133 for a free copy of its application. Any person may review the application on Michigan Gas Utilities Corporation’s website at michigangasutilities.com, or at its offices in Monroe, Coldwater, Benton Harbor and Grand Haven.

• The first public hearing in this matter will be held:

DATE: July XX, 2013

This hearing will be a prehearing conference to set future hearing dates and decide other procedural matters.

TIME: 9:00 a.m.

PRESIDING OFFICER: Administrative Law Judge XXXXXXX

LOCATION: Constitution Hall

525 West Allegan Lansing, Michigan

PARTICIPATION: Any interested person may attend and participate. The hearing site is accessible, including handicapped parking. Persons needing any accommodation to participate should contact the Commission’s Executive Secretary at (517) 241-6160 a week in advance to request mobility, visual,

hearing or other assistance. The Michigan Public Service Commission (Commission) will hold a public hearing to consider the June 7, 2013 application of Michigan Gas Utilities Corporation (MGUC), which seeks the Commission’s approval to increase revenues for the sale, transportation and distribution of natural gas. MGUC states that it has a jurisdictional revenue deficiency of $8,036,820, or 6.01%.

Page 2 U-17273

All documents filed in this case shall be submitted electronically through the Commission’s E-Dockets Website at: michigan.gov/mpscedockets. Requirements and instructions for filing can be found in the User Manual on the E-Dockets help page. Documents may also be submitted, in Word or PDF format, as an attachment to an email sent to [email protected]. If you require assistance prior to e-filing, contact Commission staff at (517) 241-6180 or by e-mail at [email protected]. Any person wishing to intervene and become a party to the case shall file a Petition to Intervene with this Commission by July XX, 2013. (Residential customers may file petitions to intervene using the traditional paper format.) The proof of service shall indicate service upon Michigan Gas Utilities Corporation’s attorney, Sherri A. Wellman, Miller, Canfield, Paddock, and Stone, P.L.C., One Michigan Avenue, Suite 900, Lansing, Michigan 48933. Any person wishing to make a statement of position without becoming a party to the case may participate by filing an appearance. To file an appearance, the individual must attend the hearing and advise the presiding administrative law judge of his or her wish to make a statement of position. All information submitted to the Commission in this matter will become public information, available on the Michigan Public Service Commission's Web site, and subject to disclosure.

Requests for adjournment must be made pursuant to the Commission’s Rules of Practice and Procedure R 460.17315 and R 460.17335. Requests for further information on adjournment should be directed to (517) 241-6060.

A copy of Michigan Gas Utilities Corporation’s request may be reviewed on the

Commission’s Web site at michigan.gov/mpscedockets, or at the office of the Commission’s Executive Secretary, 6545 Mercantile Way, Suite 7, Lansing, MI, and at the office of Michigan Gas Utilities Corporation, 899 S. Telegraph Road, Monroe, Michigan 48161. For more information on how to participate in a case, you may contact the Commission at the above address or by telephone at (517) 241-6180.

Jurisdiction is pursuant to 1909 PA 300, as amended, MCL 462.2 et seq.; 1919 PA 419, as amended, MCL 460.51 et seq.; 1939 PA 3, as amended, MCL 460.1 et seq.; 1982 PA 304, as amended, MCL 460.6h et seq.; 1969 PA 306, as amended, MCL 24.201 et seq.; and the Commission’s Rules of Practice and Procedure, as amended, 1999 AC, R 460.17101 et seq. July XX, 2013 Lansing, Michigan

mailto:[email protected]

mailto:[email protected]

http://www.michigan.gov/mpscedockets

Exhibit Schedule Title Witness

A-1 (KAD-1) A1 Revenue Deficiency (Excess) Katherine A. De Cramer, CPAA-1 (KAD-1) A2 Bridge Between 2012 Historical Test Year and 2014 Projected Test Year Katherine A. De Cramer, CPA

A-2 (KAD-2) B1 Proposed Rate Base Katherine A. De Cramer, CPAA-2 (KAD-2) B2 Proposed Utility Plant Katherine A. De Cramer, CPAA-2 (KAD-2) B3 Proposed Accumulated Provision for Depreciation Katherine A. De Cramer, CPAA-2 (KAD-2) B4 Proposed Working Capital Katherine A. De Cramer, CPAA-2 (CFH-1) B5 Capital Expenditures of Projects > $500,000 Charles F. HauskaA-2 (KAD-2) B6 Rate Base Trending Katherine A. De Cramer, CPA

A-3 (KAD-3) C1 Proposed Net Operating Income Katherine A. De Cramer, CPAA-3 (KAD-3) C2 Revenue Conversion Factor Katherine A. De Cramer, CPAA-3 (KAD-3) C3 Proposed Sales Revenue Katherine A. De Cramer, CPAA-3 (KAD-3) C4 Proposed Cost of Gas Sold Katherine A. De Cramer, CPAA-3 (KAD-3) C5 Proposed Operation and Maintenance Expense Katherine A. De Cramer, CPAA-3 (KAD-3) C6 Proposed Depreciation and Amortization Expense Katherine A. De Cramer, CPAA-3 (KAD-3) C7 Proposed General Taxes Katherine A. De Cramer, CPAA-3 (KAD-3) C8 Proposed Federal Income Taxes Katherine A. De Cramer, CPAA-3 (KAD-3) C9 Proposed State Income Taxes Katherine A. De Cramer, CPAA-3 (KAD-3) C10 Proposed Local Taxes Katherine A. De Cramer, CPAA-3 (KAD-3) C11 Proposed Allowance for Funds Used During Construction Katherine A. De Cramer, CPAA-3 (KAD-3) C12 Income Tax Effect of Interest Calculation Katherine A. De Cramer, CPAA-3 (KAD-3) C13 Operation and Maintenance Expenses including Cost of Gas Katherine A. De Cramer, CPAA-3 (KAD-3) C14 Calculation of K&M Adjustment for Increase in MGP Amortization Katherine A. De Cramer, CPAA-3 (KAD-3) C15 Calculation of K&M Adjustment for Increase in Pay-at-Risk at Target Katherine A. De Cramer, CPAA-3 (CFH-2) C16 Calculation of K&M Adjustment for Increase in Storage Field Costs Charles F. HauskaA-3 (CFH-2) C17 Calculation of K&M Adjustment for Increase in Well Logs Costs Charles F. HauskaA-3 (CFH-2) C18 Calculation of K&M Adjustment for Increase in Building Expenses Charles F. HauskaA-3 (CFH-2) C19 Calculation of K&M Adjustment for Increase due to filling Non-Union Staff Vacancies Charles F. HauskaA-3 (CFH-2) C20 Calculation of K&M Adjustment for Increase for High Risk Mains Charles F. HauskaA-3 (CFH-2) C21 Calculation of K&M Adjustment for Increase due to filling Union Staff Vacancies Charles F. HauskaA-3 (KAD-3) C22 Calculation of K&M Adjustment for Increase of Customer Relations and ICE O&M Costs Katherine A. De Cramer, CPAA-3 (KAD-3) C23 Calculation of K&M Adjustment for Uncollectible Accounts Katherine A. De Cramer, CPAA-3 (KAD-3) C24 Bad Debt Expense Calculation Katherine A. De Cramer, CPAA-3 (KAD-3) C25 Calculation of K&M Adjustment for Increase due to filling IBS Vacancies Katherine A. De Cramer, CPAA-3 (KAD-3) C26 Calculation of K&M Adjustment for Increase due to IBS Regulatory Affairs Labor Katherine A. De Cramer, CPAA-3 (KAD-3) C27 Calculation of K&M Adjustment for Increase due to A&G Loader Adjustments Katherine A. De Cramer, CPAA-3 (KAD-3) C28 Calculation of K&M Adjustment for Increase due to IBS Regulatory Affairs Non-Labor Katherine A. De Cramer, CPAA-3 (KAD-3) C29 Calculation of K&M Adjustment for Injuries and Damages Katherine A. De Cramer, CPAA-3 (KAD-3) C30 Calculation of K&M Adjustment for Benefit Costs Katherine A. De Cramer, CPAA-3 (KAD-3) C31 Calculation of K&M Adjustment for Increase in IBS Depreciation Gas Management System & ICE Hardware Katherine A. De Cramer, CPAA-3 (TLK-1) C32 Master Regulated Affiliated Interest Agreement Tracy L. KupshA-3 (TLK-1) C33 Asset Ownership by Integrys Business Support Tracy L. KupshA-3 (CMP-1) C34 Summary of Benefit Costs for MGUC Employees Christine M. Phillips, CPAA-3 (CMP-1) C35 Summary of Benefit Costs for IBS Employees Christine M. Phillips, CPAA-3 (BEK-1) C36 Inputs into Summary of Calculations of Net Present Value of Revenue Requirement Brian E. KageA-3 (MEG-1) C37 Summary of Calculations of Net Present Value of Revenue Requirement ("NPVRR") Michael E. Gerth

A-4 (LJG-1) D1 Rate of Return Summary Lisa J. Gast, CPAA-4 (LJG-1) D2 Cost of Long Term Debt Lisa J. Gast, CPAA-4 (LJG-1) D3 Cost of Short Term Debt Lisa J. Gast, CPAA-4 (LJG-1) D4 Cost of Preferred Stock Lisa J. Gast, CPAA-4 (LJG-1) D5 Cost of Common Equity Lisa J. Gast, CPAA-4 (PRM-1) D6 Summary Cost of Equity Paul R. MoulA-4 (PRM-1) D7 MGUC Historical Capitalization and Financial Statistics Paul R. MoulA-4 (PRM-1) D8 Delivery Group Historical Capitalization and Financial Statistics Paul R. MoulA-4 (PRM-1) D9 Standard & Poor's Public Utilities Historical Capitalization and Financial Statistics Paul R. MoulA-4 (PRM-1) D10 Dividend Yields Paul R. MoulA-4 (PRM-1) D11 Historical Growth Rates Paul R. MoulA-4 (PRM-1) D12 Projected Growth Rates Paul R. MoulA-4 (PRM-1) D13 Financial Risk Adjustment Paul R. MoulA-4 (PRM-1) D14 Interest Rates for Investment Grade Public Utility Bonds Paul R. MoulA-4 (PRM-1) D15 Common Equity Risk Premiums Paul R. MoulA-4 (PRM-1) D16 Component Inputs for the Capital Asset Pricing Model Paul R. MoulA-4 (PRM-1) D17 Comparable Earnings Approach Paul R. Moul

Projected Test Year Ending December 31, 2014


Michigan Gas Utilities CorporationCase No. U-17273

Index to Standard Schedules and Associated Workpapers Filed with Application for General Rate Relief

- Gas Investor Owned -

Exhibit Schedule Title Witness

Projected Test Year Ending December 31, 2014


Michigan Gas Utilities CorporationCase No. U-17273

Index to Standard Schedules and Associated Workpapers Filed with Application for General Rate Relief

- Gas Investor Owned -

A-5 (MMD-1) E1 Proposed Sales Data 2013-2017 Matthew M. DirksenA-5 (MMD-1) E1.1 Proposed Sales Data Rate Class Matthew M. DirksenA-5 (MMD-1) E2 Proposed Fixed Charge Count Data Matthew M. DirksenA-5 (MMD-1) E3 MGUC's Virtual Weather Station HDDs as Moving Averages Matthew M. DirksenA-5 (MMD-1) E4 Change in Sales Volumes from 30 to 15 Year Forecast Matthew M. DirksenA-5 (MMD-1) E5 Change in Revenues from 30 to 15 Year Forecast Matthew M. Dirksen

A-6 (JCHM-1) F1.1 MGUC 2014 Projected COSS - General Summary per MPSC Filing Requirements Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.2 MGUC 2014 Projected COSS - Detailed Summary Joylyn C. Hoffman Malueg, CMA

A-6 (JCHM-1) F1.3MGUC 2014 Projected COSS - Individual Rate Schedule Gas Revenue Requirements and Rate Base Components Joylyn C. Hoffman Malueg, CMA

A-6 (JCHM-1) F1.4 MGUC 2014 Projected COSS - Consumption Costs by Billing Unit Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.5 MGUC 2014 Projected COSS - Allocation Methodologies Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.6 MGUC Account 380 - Cost per Service Analysis Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.7 MGUC Account 381 - Cost per Service Analysis Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.8 MGUC 2014 Projected COSS - Classification and Functionalization of Costs/Investment Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.9 MGUC 2014 Projected COSS - Distribution O&M Account Translation for FERC Plant Account Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.10 MGUC Transmission System Zero-Intercept Regression Analysis Joylyn C. Hoffman Malueg, CMAA-6 (JCHM-1) F1.11 MGUC Distribution System Zero-Intercept Regression Analysis Joylyn C. Hoffman Malueg, CMAA-6 (DJT-1) F2.1 Summary of Proposed Revenues Including Cost of Gas David J. TylerA-6 (DJT-1) F2.2 Summary of Proposed Revenues Excluding Cost of Gas David J. TylerA-6 (DJT-1) F3.1 Detail of Proposed Revenues Including Cost of Gas David J. TylerA-6 (DJT-1) F3.2 Detail of Proposed Revenues Excluding Cost of Gas David J. TylerA-6 (DJT-1) F4 Comparison of Proposed Monthly Bills David J. TylerA-6 (DJT-1) F5 Proposed Tariff Sheets David J. TylerA-6 (DJT-1) F6 Calculation of Interim Rates David J. Tyler

A-7 (KAD-4) Calculation of Inflation Factors Katherine A. De Cramer, CPA

A-8 (KAD-5) Uncollectible Expense True-Up Mechanism Allocators Katherine A. De Cramer, CPA

A-9 (KAD-6) Integrys Energy Group, Inc. Awards & Recognition: 2006-2012 Katherine A. De Cramer, CPA

A-10 (NEC-1) Pay-at-Risk Plan Noreen E. Cleary

STATE OF MICHIGAN



DIRECT TESTIMONY AND EXHIBITS OF

KATHERINE A. DE CRAMER, CPA

FOR


June 7, 2013

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STATE OF MICHIGAN


* * * * *

In the matter of the application of ) MICHIGAN GAS UTILITIES CORPORATION ) for authority to increase retail natural gas rates. ) Case No. U-17273 )

QUALIFICATIONS OF

KATHERINE A. DE CRAMER, CPA PART I

Q. Please state your name, business address and position. 1

A. My name is Katherine A. De Cramer, CPA. My business address is Integrys 2

Business Support, LLC (“IBS”), 700 North Adams Street, P.O. Box 19001, Green 3

Bay, WI 54307-9001. I am a Rate Case Consultant in the Regulatory Affairs 4

Department of Integrys Energy Group, Inc (“Integrys”). Both IBS and Michigan Gas 5

Utilities Corporation (“MGUC”) are wholly-owned subsidiaries of Integrys. Integrys 6

resulted from the February 21, 2007 merger between WPS Resources Corporation 7

(“WPSR”) and Peoples Energy Corporation. 8

9

Q. For whom are you providing testimony? 10

A. I am providing testimony on behalf of MGUC. 11

12

Q. Please describe briefly your educational, professional, and utility background. 13

A. I have a Bachelors Degree from Lakeland College, Sheboygan, Wisconsin in 14

Accounting. I have a Masters Degree in Business Administration from the University 15

of Wisconsin-Oshkosh, and a Master of Science Degree in Information Systems from 16

the University of Wisconsin-Oshkosh. I am licensed in the State of Wisconsin to 17

practice as a Certified Public Accountant. 18

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1

In June of 2003, I was hired by Wisconsin Public Service Corporation (“WPS Corp”) 2

as a Revenue Requirements Forecaster in the Regulatory Affairs Department. While 3

working as a Revenue Requirements Forecaster, my primary responsibility was the 4

revenue requirements analysis for WPS Corp’s wholesale electric jurisdiction. Since 5

the acquisition of MGUC in 2006, my job responsibilities have expanded to include 6

the revenue requirements, decoupling, and Uncollectibles Expense Tracking 7

Mechanism analyses for MGUC, as well. In January of 2013, I became a Rate Case 8

Consultant within the Regulatory Affairs Department. 9

10

Q. Have you previously testified before any regulatory agency? 11

A. Yes, I have. I have submitted testimony before the Michigan Public Service 12

Commission (“Commission”) on behalf of MGUC in Case Nos. U-15990, U-16976, U-13

16977, U-17221 and U-17222. In addition, I have prepared various accounting and 14

filing exhibits for WPS Corp for presentation to the Public Service Commission of 15

Wisconsin (“PSCW”) and for MGUC for presentation to the Commission.16

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KATHERINE A. DE CRAMER DIRECT TESTIMONY

PART II

Q. What is the purpose of your pre-filed direct testimony? 1

A. The purpose of my pre-filed direct testimony is to provide an explanation of the 2

methodology used to develop MGUC’s revenue deficiency for the 2014 projected test 3

year. 4

5

Q. Are you sponsoring any exhibits in this proceeding? 6

A. Yes, I am. I am sponsoring: 7 8

1. Exhibit A-1 (KAD-1), Schedules A1 and A2, 9 10

2. Exhibit A-2 (KAD-2), Schedules B1-B4, B6, 11 12

3. Exhibit A-3 (KAD-3), Schedules C1-C15, C22-C31, 13 14 4. Exhibit A-7 (KAD-4), 15 16 5. Exhibit A-8 (KAD-5), 17

18 6. Exhibit A-9 (KAD-6), 19

20 7. Exhibit A-11 (KAD-7), Schedule A1, 21

22 8. Exhibit A-12 (KAD-8), Schedules B1-B4, and 23

24 9. Exhibit A-13 (KAD-9), Schedules C1-C11. 25

26

Q. Were these exhibits prepared by you or under your direction and supervision? 27

A. Yes, they were. 28

29

Q. Please describe Schedule A1 of Exhibit A-1 (KAD-1). 30

A. Schedule A1 of Exhibit A-1 (KAD-1) calculates MGUC’s 2014 projected test year 31

revenue deficiency based on its rate base, adjusted net operating income, rate of 32

return, and revenue conversion factor. 33

34

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A. Schedule A2 of Exhibit A-1 (KAD-1) provides the bridge between the 2012 historical 2

test year revenue deficiency and 2014 projected test year. 3

4

Q. Please describe Schedule B1 of Exhibit A-2 (KAD-2). 5

A. Schedule B1 of Exhibit A-2 (KAD-2) calculates MGUC’s 2014 projected test year rate 6

base. 7

8


A. Schedule B2 of Exhibit A-2 (KAD-2) calculates MGUC’s 2014 projected test year 10

utility plant. 11

12


A. Schedule B3 of Exhibit A-2 (KAD-2) depicts MGUC’s 2014 projected test year 14

accumulated provision for depreciation. 15

16



working capital. 19

20

Q. Please describe Schedule B5 of Exhibit A-2 (CFH-1). 21

A. Schedule B5 of Exhibit A-2 (CFH-1) will be discussed in the pre-filed direct testimony 22

of Mr. Charles F. Hauska. 23

24


A. Schedule B6 of Exhibit A-2 (KAD-2) is a trending analysis of MGUC’s rate base from 26

2007 through the 2014 projected test year. 27

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1

Q. Please describe Schedule C1 of Exhibit A-3 (KAD-3). 2

A. Schedule C1 of Exhibit A-3 (KAD-3) calculates MGUC’s 2014 projected test year 3

adjusted net operating income. 4

5



gross revenue conversion factor. 8

9


A. Schedule C3 of Exhibit A-3 (KAD-3) depicts MGUC’s 2014 projected test year total 11

revenue. 12

13


A. Schedule C4 of Exhibit A-3 (KAD-3) depicts MGUC’s 2014 projected test year cost of 15

gas. 16

17



total operation and maintenance (“O&M”) expense, exclusive of the cost of gas. 20

21



depreciation and amortization expense. 24

25



- 6 -

total for taxes other than income taxes. 1

2


A. Schedule C8 of Exhibit A-3 (KAD-3) depicts MGUC’s 2014 projected test year 4

federal income taxes. 5

6


A. Schedule C9 of Exhibit A-3 (KAD-3) depicts MGUC’s 2014 projected test year state 8

income taxes. 9

10


A. Schedule C10 of Exhibit A-3 (KAD-3) depicts MGUC’s 2014 projected test year local 12

taxes. 13

14



AFUDC. 17

18


A. Schedule C12 of Exhibit A-3 (KAD-3) calculates the Income Tax Effect of Interest for 20

MGUC’s 2014 projected test year. 21

22


A. Schedule C13 of Exhibit A-3 (KAD-3) develops the O&M costs for MGUC’s 2014 24

projected test year. 25

26


- 7 -

A. Schedule C14 of Exhibit A-3 (KAD-3) calculates the Known & Measurable (“K&M”) 1

adjustment associated with the amortization of Manufactured Gas Plant remediation 2

costs. 3

4


A. Schedule C15 of Exhibit A-3 (KAD-3) calculates the K&M adjustment for paying Pay-6

at-Risk at the “Target” level, rather than at the level paid in the 2012 historical period. 7

8

Q. Please describe Schedules C22 of Exhibit A-3 (KAD-3). 9

A. Schedule C22 of Exhibit A-3 (KAD-3) calculates the K&M adjustment related to the 10

customer relations and Integrys Customer Experience (“ICE”) 2016 project O&M 11

costs. 12

13


A. Schedule C23 of Exhibit A-3 (KAD-3) calculates the K&M adjustment associated with 15

uncollectibles expense. 16

17


A. Schedule C24 of Exhibit A-3 (KAD-3) calculates the 2014 uncollectibles expense of 19

$1,917,930, and supports Schedule C23 of Exhibit A-3 (KAD-3). 20

21



filling IBS vacancies. 24

25



- 8 -

an increase in IBS Regulatory Affairs labor. 1

2


A. Schedule C27 of Exhibit A-3 (KAD-3) calculates the K&M adjustment due to A&G 4

loader adjustments. 5

6



an increase in IBS Regulatory Affairs non-labor. 9

10



Injuries and Damages. 13

14



MGUC benefit costs. 17

18


A. Schedule C31 of Exhibit A-3 (KAD-3) calculates the K&M adjustment for increases to 20

IBS Depreciation for the Gas Management System and ICE 2016 Hardware. 21

22

Q. Please describe Exhibit A-7 (KAD-4). 23

A. Exhibit A-7 (KAD-4) calculates the inflation factors for 2013 and 2014 that were 24

applied to the 2012 historic test year O&M expenses to determine 2014 projected 25

test year O&M expenses, exclusive of K&M items. 26

27

- 9 -


A. Exhibit A-8 (KAD-5) depicts the Uncollectibles Expense True-Up Mechanism 2

Allocators. 3

4


A. Exhibit A-9 (KAD-6) is a summary of Awards & Recognition earned by Integrys and 6

Integrys subsidiaries during 2006-2012. 7

8


A. Schedule A1 of Exhibit A-11 (KAD-7) calculates MGUC’s 2012 historic test year 10


return, and revenue conversion factor. 12

13


A. Schedule B1 of Exhibit A-12 (KAD-8) calculates MGUC’s 2012 historic test year rate 15

base. 16

17


A. Schedule B2 of Exhibit A-12 (KAD-8) calculates MGUC’s 2012 historic test year 19

utility plant. 20

21


A. Schedule B3 of Exhibit A-12 (KAD-8) depicts MGUC’s 2012 historic test year 23

accumulated provision for depreciation. 24

25



- 10 -

working capital. 1

2


A. Schedule C1 of Exhibit A-13 (KAD-9) calculates MGUC’s 2012 historic test year 4

adjusted net operating income. 5

6



gross revenue conversion factor. 9

10


A. Schedule C3 of Exhibit A-13 (KAD-9) calculates MGUC’s 2012 historic test year total 12

revenue. 13

14



cost of gas. 17

18



O&M expense, exclusive of the cost of gas. 21

22


A. Schedule C6 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year total 24

depreciation and amortization expense. 25

26

27

- 11 -



for taxes other than income taxes. 3

4


A. Schedule C8 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year federal 6

income taxes. 7

8


A. Schedule C9 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year state 10

income taxes. 11

12


A. Schedule C10 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year local 14

taxes. 15

16


A. Schedule C11 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year 18

Allowance of Funds Used During Construction (“AFUDC”). 19

20



Income Tax Effect of Interest. 23

24

Background 25 Q. Are you familiar with the application of MGUC for authority to increase retail 26

gas rates? 27

A. Yes, I am. 28

- 12 -

1

Q. Please provide a brief description of MGUC and the area it serves. 2

A. MGUC is a corporation organized under the laws of the state of Delaware, with its 3

principal office located at 899 S. Telegraph Road, Monroe, Michigan 48161, and is 4

authorized to transact business in the state of Michigan. MGUC is a subsidiary of 5

Integrys, which prior to February 21, 2007, was known as WPSR. MGUC is a sister 6

utility company to UPPCO and WPS Corp, both of which are also regulated by this 7

Commission. MGUC is also a sister utility company to, among others, Minnesota 8

Energy Resources Corporation, The Peoples Gas Light and Coke Company, and 9

North Shore Gas Company, none of which is regulated by this Commission. MGUC 10

was acquired by WPSR from Aquila, Inc. on April 1, 2006 as authorized by the 11

Commission’s order in Case No. U-14657. Prior to its acquisition by WPSR, MGUC 12

conducted business as “Aquila Networks – MGU”. 13

14

MGUC is a public utility engaged in the purchase, storage, transportation, distribution 15

and sale of natural gas to approximately 166,000 customers in 147 communities in 16

the Southern and Western portions of Michigan’s lower peninsula. 17

18

Integrys and its subsidiaries have been recognized as superior performers in the 19

utility industry, as summarized on Exhibit A-9 (KAD-6). 20

21

Q. Please describe the most recent rate relief obtained by MGUC. 22

A. In the most recent rate case, Case No. U-15990, MGUC used a 2010 test year. A 23

settlement was reached and approved by the Commission granting rate relief of $3.5 24

million, based on an overall rate of return of 7.16%, and a return on common equity 25

of 10.75%, effective January 1, 2010. 26

27

- 13 -

MGUC was also authorized to implement an Uncollectibles Expense Tracking 1

Mechanism (“UETM”) under which MGUC annually defers, and subsequently 2

surcharges or credits, 80% of the difference between MGUC’s future annual Net 3

Uncollectibles Expense and the $2,009,903 of Net Uncollectibles Expense included 4

in the revenue requirement in Case No. U-15990. 5

6

In addition, MGUC was authorized to implement a revenue decoupling mechanism 7

(“RDM”). The MGUC RDM is symmetrical, and reconciles volumetric distribution 8

margin revenue (exclusive of Gas Cost Recovery revenue) per customer for the 9

Residential, Multi-Family, and Small Commercial and Industrial rate schedules. 10

MGUC compares weather adjusted actual sales per customer during each 12-month 11

period, with the base sales per customer established in Case No. U-15990 for the 12

decoupled rate schedules. MGUC annually defers an amount for the difference, 13

which is subsequently reconciled with the Commission, and surcharged or credited 14

to customers. 15

16

MGUC’s rates for retail gas service established in Case No. U-15990 do not reflect 17

the current costs of providing retail gas service, and MGUC requires further rate 18

relief. 19

20

Q. Please explain, generally, why rate relief is sought at this time. 21

A. First, the 2012 historic test year indicates that MGUC suffered a revenue deficiency 22

of $6,301,860. This corresponds to a 6.14% return on common equity. This value is 23

well below MGUC’s authorized return on common equity of 10.75% authorized in 24

MGUC’s most recent general rate case proceeding in Case No. U-15990. MGUC 25

expects to suffer a significant revenue deficiency in 2013 and 2014 as well due to: 26

27

- 14 -

First, the cost of upgrades to the MGUC gas transmission and distribution systems, 1

2

Second, margin revenues have decreased since MGUC’s most recent general rate 3

case proceeding in Case No. U-15990 from $63.5 million to $62.3 million. 4

5

Third, MGUC is projecting a higher Cost of Capital in the 2014 projected test year. 6

7

Fourth, MGUC had a number of positions that were vacant during the 2012 Historical 8

Test period. MGUC expects to fill these positions throughout 2013 and 2014, as 9

discussed in the pre-filed direct testimony of Mr. Charles F. Hauska. 10

11

Fifth, MGUC’s building expenses will increase due to needed repairs and 12

maintenance during the 2014 projected test year. 13

14

Sixth, the cost of engineering analysis on vintage natural gas transmission and 15

distribution mains. 16

17

Seventh, customer relations costs and O&M costs will increase due to a project to 18

consolidate customer service functions such as billing, payments, and web access 19

for customers to more efficiently manage their accounts. 20

21

Lastly, general inflation is expected to increase costs at a rate of about 3.74% over 22

the 2012-2014 timeframe. MGUC’s estimate for inflation for 2013 and 2014 was 23

calculated using a methodology similar to that used by MPSC Staff witness, Kirk K. 24

Megginson, in Case No. U-14893, SEMCO Energy Gas Company’s 2007 general 25

rate case. 26

27

- 15 -

As shown above, the growth in revenues has not kept up with the growth in costs. 1

2

MGUC Witnesses 3 Q. Please identify the MGUC witnesses, and indicate the subjects they will 4

address in their testimony. 5

A. I provide testimony and evidence regarding: 6

1. The revenue deficiency, including 7 a. O&M Expenses, 8 b. K&M Items, 9 c. Common equity adjustments, 10 d. Capital structure adjustments, 11 e. Rate base, and 12 f. Operating Income 13

14 2. Depreciation rates, 15

16 3. Bonus Depreciation, 17

18 4. Continuation of an uncollectible expense true-up mechanism, 19

20 5. Continuation of a revenue decoupling mechanism, 21

22 6. Interim rates, and 23

24 7. Gas Costs and Revenues. 25

26

Mr. Matthew M. Dirksen provides testimony on the sales forecast and a 27

recommendation for a change in the period for weather normalization. 28

29

Ms. Christine M. Phillips, CPA, provides testimony regarding employee benefits. 30

31

Ms. Noreen E. Cleary provides testimony about the MGUC and Integrys Pay-at-Risk 32

plan. 33

34

Mr. Charles F. Hauska provides testimony regarding capital expenditures greater 35

than $500,000, as well as K&M adjustments relating to staff vacancies, high risk 36

mains, building expenses, storage field costs and well logs costs. 37

- 16 -

1

Mr. Brian E. Kage provides testimony to describe the ICE 2016 project, as well as 2

the Intangible Benefits of ICE 2016. 3

4

Mr. Michael E. Gerth provides testimony about the Net Present Values of the ICE 5

2016 project. 6

7

Ms. Tracy L. Kupsh provides testimony on IBS charges. 8

9

Ms. Lisa J. Gast, CPA, provides testimony on MGUC’s capital structure and 10

requested return on common equity. 11

12

Mr. Paul R. Moul provides testimony on the required return on common equity. 13

14

Ms. Joylyn C. Hoffman Malueg, CMA, provides testimony on the class cost of service 15

studies. 16

17

Mr. David J. Tyler provides testimony on rate design, including the proposed rate 18

design for interim rate relief. In addition, Mr. Tyler sponsors the proposed tariff 19

changes. 20

21

Mr. John R. Wilde provides testimony on certain tax issues. 22

23

The Revenue Deficiency 24 Q. What is the amount of rate relief MGUC is seeking in this proceeding? 25

A. MGUC’s analysis of the test year ending December 31, 2014 indicates a need for an 26

annual rate increase of $8,036,820, or 6.01%, for retail gas operations. This 27

increase is based on the rates authorized in the Commission’s December 16, 2009 28

- 17 -

Order Approving Partial Settlement Agreement in Case No. U-15990 and a proposed 1

return on common equity of 10.75%, which is supported by the pre-filed direct 2

testimony of Mr. Paul R. Moul. 3

4

The rates sponsored by Mr. David J. Tyler are designed to produce the requested 5

revenue requirement, and to move toward the MGUC goal of a rate design where 6

each rate schedule will return the overall allowed rate of return, consistent with 7

MGUC’s cost of service study, MGUC’s rate design general principles, and existing 8

law. 9

10

Q. What test period is MGUC’s proposed rate increase based on? 11

A. MGUC has used a projected test year ending December 31, 2014. 12

13

O&M Expenses 14 Q. Please describe how MGUC developed 2014 O&M expenses. 15

A. MGUC started with 2012 actual O&M expenses, and inflated them to 2014 using 16

inflation factors developed by a methodology similar to that used by MPSC Staff 17

witness, Kirk D. Megginson, in Case No. U-14893, SEMCO Energy Gas Company’s 18

2007 general rate case. The inflation factors used were 1.708% for 2013, and 19

1.993% for 2014, as developed on Exhibit A-7 (KAD-4). MGUC then adjusted this 20

2014 O&M expense value for the K&M items, as described later in this testimony, 21

and in the testimony of Charles F. Hauska and Christine M. Phillips. 22

23

K&M Items 24 Q. Please describe the K&M adjustments included in the 2014 projected test year 25

O&M expenses, as detailed on Schedules C14 – C15 and C22 – C31 of Exhibit 26

A-3 (KAD-3), Schedules C16 – C21 of Exhibit (CFH-2), and Schedule C34 of 27

Exhibit A-3 (CMP-1) compared to actual O&M expenses from the 2012 historic 28

- 18 -

test year. 1

A. There are eighteen K&M adjustments. Fifteen are K&M increases, and three are 2

K&M decreases. 3

4

MGUC has defined K&M items to be any O&M cost item that was increased (or 5

decreased) at a rate other than the rates of inflation calculated on Exhibit A-7 (KAD-6

4). 7

8

The fifteen K&M increases are associated with: 9

1. Manufactured Gas Plant Remediation costs, 10 11

2. The increased costs of the Integrys Pay-at-Risk plan, 12 13

3. Storage Field Costs, 14 15

4. Well Logs Costs, 16 17

5. Building Expenses, 18 19

6. Non-Union Staff costs, 20 21

7. High Risk Mains costs, 22 23

8. Union Staff costs, 24 25

9. Customer Relations and ICE 2016 O&M costs, 26 27

10. Uncollectible Accounts, 28 29

11. IBS Staff costs, 30 31

12. IBS Regulatory Affairs Labor costs, 32 33

13. A&G Loader Adjustment, 34 35

14. IBS Regulatory Affairs Non-Labor costs, and 36 37

15. IBS Depreciation Gas Management System & ICE Hardware costs. 38 39 40

The three K&M decreases are associated with: 41

1. Injuries and Damages, 42 43

- 19 -

2. Benefits Amortizations Expense, and 1 2 3. Benefits Expense (less transitions costs and amortizations). 3

4

Each of these K&M adjustments is discussed in further detail later in this testimony, 5

or in the pre-filed direct testimony of Mr. Charles F. Hauska or Ms. Christine M. 6

Phillips. 7

8

Q. Please explain Schedule A1 of Exhibit A-1 (KAD-1). 9

A. Schedule A1 of Exhibit A-1 (KAD-1) calculates MGUC’s 2014 projected test year 10


return, and revenue conversion factor. This schedule indicates that the 2014 Total 12

Company revenue deficiency is $8,036,820, or 6.01%, based on the rates authorized 13

in the Commission’s December 19, 2009 Order Approving Partial Settlement 14

Agreement in Case No. U-15990, and a proposed 10.75% return on equity. The 15

component parts of this schedule are taken from the various sources indexed to the 16

left of each value. 17

18

Common Equity Adjustments 19 Q. What adjustments were made to the equity portion of MGUC’s capital 20

structure? 21

A. MGUC has removed certain accounts both from the 2012 historic test year and the 22

2014 projected test year. For both the 2012 historic test year and the 2014 projected 23

test year, Goodwill, Trade Name, and the associated deferred income taxes, were 24

removed from MGUC’s Equity balance. In addition, two Deferred Compensation 25

accounts were removed. This resulted in a reduction of equity of $62,231,636 in 26

2012, and $57,013,414 in 2014, which tends to reduce the revenue requirement. 27

28

29

- 20 -

Capital Adjustments 1 Q. What adjustments were made to MGUC’s overall capital structure? 2

A. For both the 2012 historic test year and the 2014 projected test year, interest bearing 3

accounts in working capital were removed from the capital structure to prevent 4

MGUC from earning a return on these items. This adjustment included items related 5

to: 6

1. GCR Over/Under Collections, 7

2. Customer Advances and Deposits, 8

3. UETM accounts, 9

4. RDM accounts, and 10

5. MI Energy Optimization. 11

This resulted in a reduction in the capital structure of $4,391,294 in 2012, and 12

$5,003,188 in 2014, which tends to reduce the revenue requirement. 13

14


A. Schedule A2 of Exhibit A-1 (KAD-1) provides the bridge between the 2012 historical 16

test year revenue deficiency and 2014 projected test year revenue deficiency. 17

18

Rate Base 19 Q. Please explain Schedule B1 of Exhibit A-2 (KAD-2). 20

A. Schedule B1 of Exhibit A-2 (KAD-2) calculates MGUC’s 2014 projected test year rate 21

base. The 2014 Total Company rate base is $210,493,148, as shown on Line 21. 22

The component parts of this schedule are taken from the various sources indexed to 23

the left of these amounts. Also, all values shown are 13-month averages. 24

25

Q. Please explain Schedule B2 of Exhibit A-2 (KAD-2). 26

A. Schedule B2 of Exhibit A-2 (KAD-2) depicts MGUC’s 2014 projected test year utility 27

plant. To arrive at the 2014 projected test year utility plant, the June 30, 2012 actual 28

- 21 -

balance of utility plant was projected forward using MGUC’s 2012, 2013, and 2014 1

construction budgets. The 2014 Total Company utility plant is $353,437,557, as 2

shown on Line 13. Also, all values shown are 13-month averages. 3

4


A. Schedule B3 of Exhibit A-2 (KAD-2) depicts MGUC’s 2014 projected test year 6

accumulated provision for depreciation. To arrive at the 2014 projected test year 7

accumulated provision for depreciation, the June 30, 2012 actual balance of 8

accumulated provision for depreciation was projected forward using MGUC’s 2012, 9

2013, and 2014 construction budgets. The 2014 Total Company accumulated 10

provision for depreciation is $189,078,201, as shown on Line 2. Also, all values 11

shown are 13-month averages. 12

13



working capital. The 2014 Total Company working capital is $46,133,792, as shown 16

on Line 41. Also, all values shown are 13-month averages. 17

18


A. Schedule B6 of Exhibit A-2 (KAD-2) presents a projected 2014 rate base developed 20

by trending analysis. The results from this trending show that MGUC’s 2014 trended 21

rate base based upon actual historical data from January 1, 2007 through December 22

31, 2012 is $11 million lower than MGUC’s 2014 projected test year rate base in the 23

instant general rate case proceeding, as shown on Line 35. 24

25

The major reasons for the difference between the 2014 trended rate base and the 26

2014 forecasted rate base include an increase in Net Plant of $25M due to 27

- 22 -

forecasted capital spending being higher than the trended amount of capital 1

spending. MGUC has recently committed to an increased capital expenditures plan 2

to improve its transmission and distribution systems. In the past few years, MGUC 3

had spent between $7.0 and $11.7 million on capital per year. In the 2012 Historical 4

Test Year, capital expenditures were $16.3 million. In the next few years, MGUC 5

plans to spend between $16.2 and $19.7 million per year on capital projects. 6

7

In addition to the Net Plant increase, other rate base variances include a decrease in 8

CWIP of $4M having closed all projects to Plant as of December 31, 2014; a 9

decrease in Working Capital, including a decrease in Temporary Cash of $4M, a 10

decrease in customer Accounts Receivable of $4M, and an increase in Accrued 11

Utility Revenue of $1.7M; and a decrease in Storage Gas of $1.6M due to a lower 12

cost of gas commodity. 13

14

Operating Income 15 Q. Please explain Schedule C1 of Exhibit A-3 (KAD-3). 16


adjusted net operating income. The 2014 Total Company adjusted net operating 18

income is $8,565,375, as shown on Line 22. 19

20

Q. Please explain Schedule C2 of Exhibit A-3 (KAD-3). 21


gross revenue conversion factor. The 2014 gross revenue conversion factor is 23

1.637, as shown on Line 14. 24

25

26



- 23 -

total revenue. The 2014 Total Company total revenue is $134,862,467, as shown on 1

Line 6. 2

3



cost of gas. The 2014 Total Company cost of gas is $71,684,716, as shown on Line 6

7. 7

8



total O&M expense, exclusive of the cost of gas. The 2014 Total Company total 11

O&M expense, exclusive of the cost of gas, is $37,518,049, as shown on Line 19. 12

13



depreciation and amortization expense. The 2014 Total Company total depreciation 16

and amortization expense is $9,779,652, as shown on Line 6. 17

18



total for taxes other than income taxes. The 2014 Total Company total for taxes 21

other than income taxes is $4,504,777, as shown on Line 32. 22

23



federal income taxes. The 2014 Total Company federal income taxes are 26

$2,509,208, as shown on Line 2. 27

- 24 -

1


A. Schedule C9 of Exhibit A-3 (KAD-3) depicts MGUC’s 2014 projected test year state 3

income taxes. The 2014 Total Company state income taxes are $295,743, as shown 4

on Line 2. 5

6


A. Schedule C10 of Exhibit A-3 (KAD-3) depicts MGUC’s 2014 projected test year local 8

taxes. The 2014 Total Company local taxes are $0, as shown on Line 2. 9

10



AFUDC. The 2014 Total Company AFUDC is $0, as shown on Line 5. 13

14


A. Schedule C12 of Exhibit A-3 (KAD-3) calculates the Income Tax Effect of Additional 16

Interest Allowed for MGUC’s 2014 projected test year. The tax effect of additional 17

interest allowed multiplied by the current income tax rate of 41% is $4,947, as shown 18

on line 20. 19

20


A. Schedule C13 of Exhibit A-3 (KAD-3) develops the O&M costs for MGUC’s 2014 22

projected test year. This series of workpapers starts with 2012 actual O&M 23

amounts. The 2012 expenses were first inflated at the estimated inflation factors of 24

1.708% for 2013 and 1.993% for 2014, as calculated on Exhibit A-7 (KAD-4). Next, 25

the Cost of Gas accounts were trued up to the 2014 forecasted costs. Lastly, O&M 26

was adjusted for K&M items. 27

- 25 -

1


A. Schedule C14 of Exhibit A-3 (KAD-3) calculates the K&M increase regarding costs to 3

remediate former manufactured gas plant sites. In its March 30, 1994 order in Case 4

No. U-10503, and its November 10, 2005 order in Case No. U-14657, the 5

Commission authorized MGUC to employ deferred accounting treatment for costs 6

associated with the remediation of former manufactured gas plant sites. Since 2002, 7

MGUC has conducted remediation activities at former manufactured gas plant sites 8

located in: 9

1. Benton Harbor (Remedial investigations, source removal, groundwater 10 monitoring, and property acquisition) 11

12 2. Cadillac (Remedial investigations, groundwater monitoring, source 13

removal, and property acquisition) 14 15

3. Coldwater Race Street (Remedial investigations, source removal, 16 groundwater monitoring, and closure documentation) 17

18 4. Grand Haven (Remedial investigations, source removal, and groundwater 19

monitoring) 20 21

5. Hillsdale (Remedial investigations, source removal, and groundwater 22 monitoring) 23

24 6. Otsego (Remedial investigations, source removal, groundwater 25

monitoring, and property acquisition) 26 27

7. South Haven (Remedial investigations, source removal, and property 28 acquisition) 29

30 8. Sturgis (Groundwater monitoring and closure documentation) 31

32 9. Traverse City (Groundwater monitoring) 33

34 10. Coldwater Chicago Street (Remedial investigations). 35

36

MGUC calculated the 2014 projected test year amortization expense in accordance 37

with the Commission’s current practice of amortizing deferred manufactured gas 38

plant remediation costs on a vintage basis over ten years. Therefore, for the 2014 39

projected test year, MGUC has calculated a K&M increase of $127,247 in Account 40

- 26 -

735, as shown on Line 8. 1

2

Q. Are environmental response activities performed and costs incurred under the 3

direction of the Michigan Department of Environmental Quality (MDEQ), as 4

required under Part 201, Environmental Remediation of the Natural Resources 5

and Environmental Protection Act (NREPA), 1994 PA 451, as amended (Act 6

451)? 7

A. Yes, they are. 8

9

Q. For what time period has Commission Staff already audited MGUC’s 10

Manufactured Gas Plant expenses? 11

A. As documented in Case No. U-15990, Data Request 01-JEL-10, provided on 12

September 24, 2009, Commission Staff has audited Manufactured Gas Plant 13

expenses through August 21, 2009 business. 14

15


A. Schedule C15 of Exhibit A-3 (KAD-3) calculates the $68,127 K&M adjustment 17

associated with Pay-at-Risk. Page 1 of 3 of Schedule C30, Exhibit A-3 (KAD-3) 18

calculates the K&M increase; page 2 of 3 identifies the removal of the 2012 inflated 19

Pay-at-Risk expenses; and page 3 of 3 calculates the inclusion of the forecasted 20

2014 Pay-at-Risk expenses. This adjustment was made so that all Pay-at-Risk 21

expenses that are included in the 2014 forecasted test year were included at the 22

“target” level. 23

24


A. Schedule C22 of Exhibit A-3 (KAD-3) calculates the K&M adjustment related to the 26

customer relations and ICE 2016 O&M costs related to the ICE 2016 project. The 27

- 27 -

ICE 2016 project is further explained in the pre-filed direct testimony of Mr. Brian E. 1

Kage and Mr. Michael E. Gerth. 2

3

The O&M costs related to customer relations and the ICE 2016 project are recorded 4

in FERC Accounts 901, 903, 905, 907, and 908. These costs can be summarized 5

into three categories: Customers Relations Labor, Customer Relations Non-Labor, 6

and ICE 2016 O&M. 7

8

The Customer Relations Labor and Customer Relations Non-Labor costs include the 9

impact of the ICE Project on IBS Customer Relations operational O&M costs 10

allocated to MGUC. These summaries exclude ICE 2016 Project Implementation 11

Costs except for the portion of IBS Customer Relations operating labor resources 12

that are forecasted to be capitalized during 2014 and 2015; these are recognized as 13

a partial return of that labor to O&M in 2015 and full return in 2016. 14

15

The ICE 2016 O&M costs that are depicted are the costs incurred during the 16

implementation phases of the ICE 2016 Project. These costs include project O&M 17

expense contingency for internal Integrys labor, contracted labor, Accenture partner 18

labor and expenses, software O&M, and miscellaneous O&M. The project O&M 19

expense for internal labor has been subtracted out of the project total O&M to avoid 20

double counting the O&M expense for internal labor between the Project O&M, IBS 21

Customer Relations O&M, and ITS operational O&M. 22

23

Schedule C22 of Exhibit A-3 (KAD-3), Page 2 of 2, presents the expenses in FERC 24

accounts 901, 903, 905, 907, and 908 for the 2012 Historical Test Year, summarized 25

by the three categories discussed above. Line 1 contains Customer Relations Labor 26

costs of $577,313; Line 2 contains Customer Relations Non-Labor costs of 27

- 28 -

$4,905,754; Line 3 contains ICE 2016 O&M costs of $79,074; and Line 4 displays 1

the balance contained in the five accounts of $1,104,356; for a total in these 2

accounts of $6,666,497. The 2012 costs are inflated based on the inflation factors 3

presented in Exhibit A-7 (KAD-4). The inflated 2014 forecasted costs in accounts 4

901, 903, 905, 907, and 908 are further adjusted for K&M costs of $372,785 related 5

to the customer relations and ICE 2016 project O&M costs for 2014, resulting in a 6

total 2014 forecasted amount of $7,288,282, as shown on page 1 of 2 of Schedule 7

C22, Exhibit A-3 (KAD-3). 8

9



uncollectibles expense. MGUC has forecasted its 2014 projected test year 12

uncollectibles expense to equal a 3-year historical average of 2010 - 2012, which is 13

$1,917,930. This results in a total K&M increase of $422,307 in Account 904, as 14

shown on Line 8. 15

16


A. Schedule C24 of Exhibit A-3 (KAD-3) calculates the 2014 projected test year 18

uncollectibles expense of $1,917,930 referenced in Schedule C23 of Exhibit A-3 19

(KAD-3). As shown on this exhibit, for the 3-year period 2010-2012, MGUC’s 20

average net uncollectibles have equaled 1.43389% of MGUC’s tariff revenues. This 21

value was multiplied by MGUC’s 2014 projected test year retail revenues of 22

$133,757,462 to arrive at a 2014 projected test year uncollectibles expense of 23

$1,917,930, as shown on Line 11. MGUC proposes that its UETM be updated with 24

this new value for uncollectibles expense. 25

26

27

- 29 -


A. Schedule C25 of Exhibit A-3 (KAD-3) calculates the $213,581 K&M adjustment for 2

vacant positions IBS experienced in 2012. As shown on Schedule C25, Page 2 of 2, 3

this adjustment was calculated by dividing the average base and overtime of IBS 4

internal O&M by the average FTE’s in 2012. This average O&M per FTE was then 5

multiplied by the 72 vacant FTE’s IBS experienced in 2012. MGUC is allocated 3.6% 6

of these IBS costs; the remaining costs are allocated to the other Integrys 7

subsidiaries. The result was then multiplied by the inflation factor from Exhibit A-7 8

(KAD-4) to calculate the K&M adjustment. 9

10


A. Schedule C26 of Exhibit A-3 (KAD-3) calculates the $78,433 K&M adjustment related 12

to an increase in regulatory labor expenses associated with a rate case. There was 13

no rate case in 2012; therefore, there were no costs associated with a rate case in 14

the 2012 Historical Test Year O&M expenses. 15

16



related to the elimination of the A&G Loader that was previously added to all MGUC 19

capital projects. This practice is not followed at the other Integrys utilities and in the 20

interest of standardizing accounting practices, the A&G Loader is being eliminated. 21

The value was calculated as the five-year historical average of the A&G loader, as 22

shown on line 15. 23

24


A. Schedule C28 of Exhibit A-3 (KAD-3) calculates the $6,395 K&M adjustment related 26

to an increase in regulatory non-labor expenses associated with a rate case. There 27

- 30 -

was no rate case in 2012; therefore, there were no costs associated with a rate case 1

in the 2012 Historical Test Year O&M expenses. 2

3


A. Schedule C29 of Exhibit A-3 (KAD-3) calculates the decrease of $22,007 K&M 5

adjustment associated with injuries and damages. MGUC has forecasted its 2014 6

projected test year injuries and damages expense to be equal to its 3-year historical 7

average, which is $446,851 as shown on line 12. 8

9


A. Schedule C30 of Exhibit A-3 (KAD-3) calculates the Benefits K&M decrease for 11

MGUC. 12

13

First, in the Commission’s January 9, 2007 Order in Case No. U-15138, the 14

Commission authorized the deferral and amortization of MGUC’s pension and OPEB 15

obligations recorded on its opening balance sheet as a result of the purchase of 16

MGUC from Aquila. As a result of this order, MGUC annually amortized $1,594,678 17

of expense, which was decreased to $1,594,610 for 2012, due to an amortization 18

that ended. Due to the combination of the lower amortization amount, and because 19

this amortization is not impacted by inflation, a K&M decrease of $90,559 in Account 20

926 was calculated, as shown on Line 8 of page 1. 21

22

Second, excluding the Account 926 impact of the K&M adjustment in Schedule C15 23

of Exhibit A-3 (KAD-3), and the amortization discussed above, MGUC is forecasting 24

a K&M decrease for MGUC employees of $451,492 in Account 926, as shown on 25

Line 8 of page 2. Further information regarding this calculation can be found on 26

page 2 of Schedule C30 of Exhibit A-3 (KAD-3), and in the pre-filed direct testimony 27

- 31 -

of Christine M. Phillips. 1

2

Taken together, these two adjustments result in a net K&M decrease of $542,051 in 3

Account 926. 4

5



related to IBS depreciation of a Gas Management System (“GMS”) and ICE 2016 8

hardware. The annual IBS depreciation is allocated to each business unit based on 9

gas throughput; therefore, MGUC will be allocated $98,863. The annual IBS 10

depreciation for MGUC for the ICE 2016 hardware is $20,947. Taken together, 11

these values sum to $119,810. 12

13

Q. Please explain Exhibit A-7 (KAD-4). 14

A. Exhibit A-7 (KAD-4) calculates the inflation factors for 2013 and 2014 that were 15

subsequently applied to 2012 historic year O&M expenses to calculate 2014 16

projected test year O&M expenses. The schedule calculates the simple average of 17

five independent inflation forecasts, and results in an inflation factor if 1.708% for 18

2013, and 1.993% for 2014. 19

20

This methodology is similar to that used by MPSC Staff witness, Kirk K. Megginson, 21

in Case No. U-14893, SEMCO Energy Gas Company’s 2007 general rate case. 22

23

Q. Please explain Exhibit A-8 (KAD-5). 24

A. Exhibit A-8 (KAD-5) is a schedule of the Uncollectibles Expense Tracking 25

Mechanism (“UETM”) allocation factors for MGUC. As previously stated, MGUC 26

requests to extend its currently authorized UETM until its next general rate case. 27

- 32 -

Therefore, MGUC here provides updated allocators for the UETM, which are based 1

on actual Uncollectibles Expense from 2013. 2

3


A. Exhibit A-9 (KAD-6) is a summary of Awards & Recognition earned by Integrys and 5

Integrys subsidiaries during 2006-2012. 6

7


A. Schedule A1 of Exhibit A-11 (KAD-7) calculates MGUC’s 2012 historic test year 9


return, and revenue conversion factor. This schedule develops the 2012 Total 11

Company revenue deficiency of $6,301,860, as shown on Line 16, using a 10.75% 12

return on equity. The component parts of this schedule are taken from the various 13

sources indexed to the left of these amounts. 14

15


A. Schedule B1 of Exhibit A-12 (KAD-8) calculates MGUC’s 2012 historic test year rate 17

base. The 2012 Total Company rate base is $194,076,269, as shown on Line 21. 18

The component parts of this schedule are taken from the various sources indexed to 19

the left of these amounts. 20

21



utility plant. The 2012 Total Company utility plant is $314,401,740, as shown on Line 24

13. 25

26

27

- 33 -


A. Schedule B3 of Exhibit A-12 (KAD-8) depicts MGUC’s 2012 historic test year 2

accumulated provision for depreciation. The 2012 Total Company accumulated 3

provision for depreciation is $171,640,370, as shown on Line 2. 4

5



working capital. The 2012 Total Company working capital is $51,314,899, as shown 8

on Line 41. 9

10



adjusted net operating income. The 2012 Total Company adjusted net operating 13

income is $9,943,804, as shown on Line 22. 14

15



gross revenue conversion factor. The 2012 gross revenue conversion factor is 18

1.637, as shown on Line 14. 19

20



revenue. The 2012 Total Company total revenue is $122,621,203, as shown on Line 23

6. 24

25


A. Schedule C4 of Exhibit A-13 (KAD-9) calculates MGUC’s 2012 historic test year cost 27

- 34 -

of gas. The 2012 Total Company cost of gas is $63,534,006, as shown on Line 7. 1

2



O&M expense, exclusive of the cost of gas. The 2012 Total Company total O&M 5

expense, exclusive of the cost of gas, was $33,647,791, as shown on Line 19. 6

7


A. Schedule C6 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year total 9

depreciation and amortization expense. The 2012 Total Company total depreciation 10

and amortization expense is $8,115,375, as shown on Line 6. 11

12



for taxes other than income taxes. The 2012 Total Company total for taxes other 15

than income taxes is $4,264,075, as shown on Line 31. 16

17


A. Schedule C8 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year federal 19

income taxes. The 2012 Total Company federal income taxes are $2,868,188, as 20

shown on Line 2. 21

22


A. Schedule C9 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year state 24

income taxes. The 2012 Total Company state income taxes are $200,010, as shown 25

on Line 2. 26

27

- 35 -


A. Schedule C10 of Exhibit A-13 (KAD-9) depicts MGUC’s 2012 historic test year local 2

taxes. The 2012 Total Company local taxes are $0, as shown on Line 2. 3

4



AFUDC. The 2012 Total Company AFUDC is $0, as shown on Line 5. 7

8


A. Schedule C12 of Exhibit A-13 (KAD-9) calculates the Income Tax Effect of Additional 10

Interest Allowed for MGUC’s 2012 historical test year. The tax effect of additional 11

interest allowed multiplied by the current income tax rate of 41% is $47,954, as 12

shown on line 20. 13

14

Depreciation Rates 15 Q. What depreciation rates were used in this rate case? 16

A. As required by the Commission’s December 23, 2008 and February 20, 2009 Orders 17

in Case No. U-15895, MGUC used its currently approved depreciation rates and 18

practices approved in Case No. U-15963 to determine its 2014 revenue requirement 19

in the instant general rate case. 20

21

Also, in accordance with the Commission’s October 14, 2010 Order in Case No. U-22

15963, MGUC had filed a depreciation study on October 12, 2012. 23

24

Bonus Depreciation 25 Q. How was “bonus depreciation” calculated in the 2012 historic test year, and 26

the 2014 projected test year? 27

A. In February 2009, the American Recovery and Reinvestment Act of 2009 (“ARRA”) 28

- 36 -

was signed into law. Included in ARRA is a provision that provides MGUC with 1

additional opportunities to claim tax deductions for “bonus depreciation” for certain 2

assets placed in service during 2009. For 2012, bonus depreciation remained, but 3

was reduced to 50 percent. The American Taxpayer Relief Act of 2012 was signed 4

into law on January 2, 2013. This extends 50 percent bonus depreciation through 5

2013 (through 2014 in the case of certain period production property and 6

transportation property). This bonus depreciation was included when the revenue 7

requirement for the 2014 projected test year was calculated. 8

9

Uncollectible Expense True-Up Mechanism 10 Q. Please explain the 2014 uncollectible expense forecasted for the 2014 11



uncollectibles expense. To be consistent with past practice, MGUC has forecasted 14

its 2014 projected test year uncollectibles expense equal to its 3-year historic 15

average, which is $1,917,930. This results in a total K&M increase of $422,307 in 16

Account 904. 17

18

Schedule C24 of Exhibit A-3 (KAD-3) calculates the 2014 projected test year 19

uncollectibles expense of $1,917,930 referenced in Schedule C23 of Exhibit A-3 20

(KAD-3). As shown on this exhibit, for the 3-year period 2010-2012, MGUC’s 21

average net uncollectibles have equaled 1.43389% of MGUC’s tariff revenues. This 22

value was multiplied by MGUC’s 2014 projected test year revenues of $133,757,462 23

to arrive at a 2014 projected test year uncollectibles expense of $1,917,930. 24

25

Q. Please explain the UETM that MGUC was authorized in U-15990. 26

A. MGUC was authorized to implement a UETM under which MGUC annually defers, 27

and subsequently surcharges or credits, 80% of the difference between MGUC’s 28

- 37 -

future annual Net Uncollectibles Expense and the $2,009,903 of Net Uncollectibles 1

Expense included in the revenue requirement in Case No. U-15990. 2

3

Q. Should the Commission allow MGUC’s UETM to continue? 4

A. Yes, it should. MGUC proposes that the UETM be continued in its current format; 5

however, updated with the 2014 uncollectibles allowance of $1,917,930 as 6

calculated on Exhibit A-3 (KAD-3) Schedule C23, and with updated allocators as 7

shown on Exhibit A-8 (KAD-5). 8

9

Decoupling Mechanism 10 Q. Is MGUC currently authorized the use of a revenue decoupling mechanism? 11

A. Yes, MGUC is. 12

13

Q. Please describe the revenue decoupling mechanism. 14

A. MGUC was authorized to implement a revenue decoupling mechanism in Case No. 15

U-15990. The MGUC RDM is symmetrical, and reconciles volumetric distribution 16

margin revenue (exclusive of Gas Cost Recovery revenue) per customer for the 17

Residential, Multi-Family, and Small Commercial and Industrial rate schedules. 18

MGUC will compare weather adjusted actual sales per customer during each 12-19

month period, with the base sales per customer established in Case No. U-15990 for 20

the decoupled rate schedules. MGUC annually defers an amount for the difference, 21

which is subsequently reconciled with the Commission, and surcharged or credited 22

to customers. 23

24

Q. Should the Commission allow MGUC’s RDM to continue? 25

A. Yes, it should. MGUC proposes that the RDM be continued in its current format; 26

however, it should be updated with the 2014 base sales per customer. 27

28

- 38 -

Interim Rates 1 Q. Does MGUC intend to self-implement interim rates in this general rate 2

proceeding? 3

A. Yes, MGUC does. In accordance with MCL 460.6a(1), MGUC intends to self-4

implement interim rates for service rendered on and after January 1, 2014. The 5

interim rate design is discussed in the pre-filed direct testimony of Mr. David J. Tyler. 6

7

Matching of Gas Costs and Gas Cost Revenues 8 Q. Has MGUC matched gas costs and gas cost revenues in the calculation of the 9

revenue deficiency in this general rate case proceeding? 10

A. Yes, we have. The gas cost recovery factors used to calculate Revenues on Present 11

Rates in this general rate case proceeding were calculated, such that gas costs 12

equaled gas cost revenues, resulting in one-for-one recovery of gas costs. 13

14

Q. Does this conclude your pre-filed direct testimony? 15

A. Yes, it does. 16

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-1 (KAD-1)Revenue Deficiency (Sufficiency) Schedule: A1For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1

Witness: Katherine A. De Cramer, CPA

(a) (b) (c)

LineNo. Description Source Total12 Rate Base Exh. A-2, Sch. B1 210,493,148$ 34 Operating Income Exh. A-3, Sch. C1 8,565,37556 Overall Rate of Return Line 4 ÷ Line 2 4.0692%78 Rate of Return Exh. A-4, Sch. D1 6.4020%910 Income Requirements Line 2 x Line 8 13,475,7551112 Income Deficiency (Sufficiency) Line 10 - Line 4 4,910,3801314 Revenue Conversion Factor Exh. A-3, Sch. C2 1.63671516 Revenue Deficiency (Sufficiency) Line 12 x Line 14 8,036,820$

Schedule A1

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-1 (KAD-1)Projected Revenue Deficiency (Sufficiency) Schedule: A2Bridge Between 2012 Historical Test Year and 2014 Projected Test Year Page: 1 of 1Projected 12 Month Period Ending, December 31, 2014 Witness: Katherine A. De Cramer, CPA

(a) (b) (c)

LineNo. Description

1 2012 Revenue Deficiency/(Sufficiency) 6,301,86023 2014 Gas Margin -4,090,5554 Other Adjustment 056 Non-Fuel O&M7 Inflation 1,249,3278 Manufactured Gas Plant Remediation Amortization 127,2479 Company Use 268,248

10 Incentives Adjustments 68,12711 Storage Field Costs 70,50212 Well Log Costs 80,00013 Building Expenses 250,00014 Non-Union Vacancies Filled 407,00015 High Risk Mains 250,00016 Union Staff Vacancies Filled 505,00017 Customer Relations and ICE2016 O&M Costs 372,78518 Uncollectible Accounts 422,30719 IBS Vacancies Filled 213,58120 IBS Regulatory Affairs Increase -- Labor 78,43321 A&G Loader Adjustment 146,06922 IBS Regulatory Affairs -- Non-Labor 6,39523 Injuries & Damages -22,00724 Benefits Expense (Amortizations Only) -90,55925 Benefits Expense (Less Transition Costs and Amortizations) -451,49226 IBS Depreciation Gas Management System & ICE Hardware 119,8102728 Total Non-Fuel O&M Adjustments 4,070,77329

Schedule A2

293031 Property Taxes 160,83132 Payroll Taxes 77,43433 Other Taxes 2,4373435 240,7023637 Capital Projects Depreciation38 Production 51,47339 Transmission 139,97640 Distribution 1,434,22741 Storage 38,6024243 Total Depreciation 1,664,278444546 Rate Base Return -189,6264748 Rate of Return (ROE - 10.75%) 049 Other 39,3885051 2014 Revenue Deficiency 8,036,8205253 2014 Tariff Revenues 133,757,46754

Rate Increase Percentage 6.01%

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-2 (KAD-2)Rate Base Schedule: B1For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(b) (c)

LineNo. Source Rate Base12 Plant in Service Exh A-2, Sch B2 353,437,557$ 3 Plant Held for Future Use Exh A-2, Sch B2 04 Construction Work in Progress Exh A-2, Sch B2 05 Total Utility Plant 353,437,557$ 67 Less: Depreciation Reserve Exh A-2, Sch B3 189,078,20189 Net Utility Plant 164,359,356$ 1011 Net Capital Lease Property 01213 Total Utility Property and Plant 164,359,356$ 1415 Less: Capital Lease Obligations 01617 Net Plant 164,359,356$ 1819 Allowance for Working Capital Exh A-2, Sch B4 46,133,7922021 Total Rate Base 210,493,148$

(a)

Description

Schedule B1

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-2 (KAD-2)Utility Plant Schedule: B2For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

MPSCLine AccountNo. Description No. Utility Plant12 Plant in service 101 345,069,392$ 3 Plant purchased or sold 102 - 4 Plant leased to others 104 - 5 Completed construction not classified 106 4,766,404 6 Gas Stored Base Gas 117 3,601,761 7 Plant in Service 353,437,557$ 89 Plant held for future use 1051011 Construction work in progress 107 - 1213 Total Utility Plant 353,437,557$

Schedule B2

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-2 (KAD-2)Accumulated Provision for Depreciation Schedule: B3For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b)

Line Accum. Prov.No. Description Source for Depr.12 Workpapers 2014 Page 10 189,078,201$

Schedule B3

Total Accumulated Provision for Depreciation

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-2 (KAD-2)Working Capital Schedule: B4For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b)

Line WorkingNo. Description Source Capital12 Assets3 Utility Plant-ARO Workpapers 2014 Page 77 1,387,148$ 4 Accumulated Depreciation-ARO Workpapers 2014 Page 77 (402,942) 5 Cash/Bank Balance Workpapers 2014 Page 16 189,780 6 Temporary Cash Workpapers 2014 Page 82 - 7 Notes Receivable Workpapers 2014 Page 82 2,687 8 Customer A/R Workpapers 2014 Page 85 8,428,449 9 Other A/R Workpapers 2014 Page 85 712,997 10 Accumulated Provision Uncollectible Accounts Workpapers 2014 Page 85 (1,567,877) 11 Accounts Receivable from Associated Companies Workpapers 2014 Page 85 64,805 12 Taxes Receivable Other Companies Workpapers 2014 Page 85 - 13 Prepayments Workpapers 2014 Page 15 527,688 14 Accrued Utility Revenues Workpapers 2014 Page 85 8,446,355 15 Fuel Stock/Gas Storage Workpapers 2014 Page 10 14,976,515 16 Other Materials & Supplies Workpapers 2014 Page 10 512,219 17 Miscellaneous and Accrued Workpapers 2014 Page 85 2,710,638 18 Derivative Assets Workpapers 2014 Page 85 172,882 19 Int & Div Receivable Workpapers 2014 Page 85 57 20 Other Deferred Debits not in Ratebase Workpapers 2014 Page 89 62,561,444 2122 Total Assets 98,722,845$ 2324 Liabilities25 Def Cr-Sup Ret Sel SERP Workpapers 2014 Page 95 8,931,907$ 26 Accum Provision for Injuries & Damages Workpapers 2014 Page 96 5,468 27 Asset Retirement Obligation Workpapers 2014 Page 103 1,851,532 28 Accounts Payable Workpapers 2014 Page 104 14,605,226 29 Accounts Payable Other Workpapers 2014 Page 106 3,058,694 30 Accrued Taxes Workpapers 2014 Page 17 2,663,523 31 Accrued Interest Workpapers 2014 Page 108 13,932 32 Tax Collections Payable Workpapers 2014 Page 110 6,676 33 Miscellaneous Current/Accrued Workpapers 2014 Page 111 1,812,708 34 Derivative Liab Workpapers 2014 Page 112 11,660 35 Other Deferred Credits Workpapers 2014 Page 113 19,273,903 36 Other Regulatory Liabilities Workpapers 2014 Page 115 353,824 37 Accumulated Deferred Taxes N/A - 3839 Total Liabilities 52,589,053$ 4041 Total Working Capital 46,133,792$

Schedule B4

Case No.: U-17273 Exhibit No.: A-2 (KAD-2)

Schedule No.: B6Page: 1 of 1


Michigan Gas Utilities CorporationSummary of Corporate Gas Rate Base Trending AnalysisFor the Period 2007 - 2012

Historical Historical Historical Historical Historical Historical Projected DifferenceLine 13-mo-avg 13-mo-avg 13-mo-avg 13-mo-avg 13-mo-avg 13-mo-avg Trended Trended Test Year of ForecastedNo. Accounts 2007 2008 2009 2010 2011 2012 2013 2014 2014 vs. Trended12 Gross Plant 101, 106 274,664,066 280,532,632 288,960,941 294,398,728 300,347,751 310,262,590 310,873,145 311,484,902 353,437,556 41,952,6553 Utility Plt Acq Adj 114 0 0 0 0 0 0 0 0 0 04 Accum Depreciation - S/L 108, 111, 254185 (138,179,631) (143,583,513) (150,386,255) (157,648,734) (165,321,946) (171,640,370) (171,978,135) (172,316,565) (189,078,201) (16,761,636)5 Acc Prov Amor Plt Acq Adj 115 0 0 0 0 0 0 0 0 0 06 Net Nuclear Fuel 120% 0 0 0 0 0 0 0 0 0 07 Net Plant 136,484,435 136,949,120 138,574,686 136,749,994 135,025,805 138,622,220 138,895,010 139,168,337 164,359,355 25,191,01889 CWIP 107 299,777 789,434 547,404 938,076 2,308,951 4,139,150 4,147,295 4,155,457 (0) (4,155,457)

10 Future Use Plant 105 0 0 0 0 0 0 0 0 0 011 Plant Total 136,784,212 137,738,554 139,122,089 137,688,070 137,334,756 142,761,370 143,042,305 143,323,793 164,359,355 21,035,5621213 Working Capital (BCR) Multiple Accts 28,478,440 30,062,777 33,718,563 27,162,741 36,759,224 34,923,284 34,992,008 35,060,868 32,591,114 (2,469,753)14 Cash & Bank 131, 134, 135 1,597,540 2,802,567 545,196 533,215 736,674 664,732 666,040 667,351 189,780 (477,570)15 Gas Storage 151, 152, 164 36,035,101 43,247,633 33,372,939 29,213,824 22,174,713 16,547,698 16,580,262 16,612,889 14,976,515 (1,636,374)16 Other M&S 154, 163 697,243 593,168 427,014 317,655 457,667 488,152 489,113 490,075 512,219 22,14417 Investments Multiple Accts 0 0 0 0 0 0 0 0 0 018 Investments - Deferred Txs Multiple Accts 0 0 0 0 0 0 0 0 0 019 Prepayments 165 267,825 181,829 766,988 1,804,705 371,064 471,257 472,184 473,113 527,688 54,57520 Amort of Appropriated RE 215100 0 0 0 0 0 021 Sub-Total 67,076,149 76,887,974 68,830,700 59,032,141 60,499,342 53,095,122 53,199,606 53,304,296 48,797,317 (4,506,979)2223 Taxes 236 (2,481,168) (1,292,655) (1,129,470) (921,245) (2,473,079) (1,780,223) (1,783,727) (1,787,237) (2,663,523) (876,286)24 Customer Advances 252 0 0 0 0 0 0 0 0 0 025 Cust Adv. Def. Taxes 190120, 190220 0 0 0 0 0 0 0 0 0 026 M&S Deferred Taxes 283110, 283210 0 0 0 0 0 0 0 0 0 027 Sub-Total (2,481,168) (1,292,655) (1,129,470) (921,245) (2,473,079) (1,780,223) (1,783,727) (1,787,237) (2,663,523) (876,286)2829 201,379,192 213,333,873 206,823,320 195,798,966 195,361,019 194,076,269 194,458,185 194,840,852 210,493,149 15,652,2973031 Trended Increase N/A N/A N/A N/A N/A N/A 0.20% 0.20% N/A3233 Adjustments Multiple Accts 10,262,984 10,557,768 10,470,062 7,917,874 267,531 1,072,189 1,074,299 1,076,413 5,382,266 4,305,8533435 RATE BASE as ADJUSTED 191,116,209 202,776,105 196,353,257 187,881,092 195,093,488 193,004,080 193,383,886 193,764,439 205,110,883 11,346,4443637 Trended Increase: 0.20%

RATE BASE

*** 13 month average represents a 24-point average

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Net Operating Income Schedule: C1For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b)

NetLine OperatingNo. Description Source Income12 Operating Revenues Exh. A-3, Sch. C3 134,862,467$ 34 Operating Expenses5 Cost of Gas Exh. A-3, Sch. C4 71,684,7166 Operations and Maintenance Expenses Exh. A-3, Sch. C5 37,518,0497 Depreciation and Amortization Exh. A-3, Sch. C6 9,779,6528 General Taxes Exh. A-3, Sch. C7 4,504,7779 Income Taxes Exh. A-3, Sch. C8, C9 & C10 2,804,95110 Total Operating Expenses 126,292,145$ 1112 Operating Income 8,570,322$ 1314 Operating Income Adjustments15 Allowance For Funds Used During Construction - 016 Loss on Reacquired Securities - 017 Interest - 018 Income Tax Effect of Interest Exh. A-13, Sch. C12 4,94719 Interest Synchronization Adjustment 020 Total Operating Income Adjustments 4,947$ 2122 Adjusted Net Operating Income 8,565,375$

Schedule C1

Michigan Public Service Commission Case No.: U-17273

Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)

Revenue Conversion Factor Schedule No.: C2

Page: 1 of 1


(a) (b) (c) (d)

Line Calc.

No. Description Logic 2014

1

2 Income Before Income Taxes 100.000%

3

4 Michigan Corporate Income Tax Rate 6.0000%

5

6 Federal Income Tax Base Ln 2 - Ln 7 94.000%78 Times Federal Income Tax Rate 35.000%910 Federal Income Tax Ln 8 x Ln 10 32.900%

1112 Income After Taxes Ln 8 - Ln 12 61.100%

1314 Gross Revenue Conversion Factor Ln 2 / Ln 14 1.6367

Schedule C2

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Sales Revenue Schedule No.: C3For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line SalesNo. Description Source Revenue12 Present Revenues Workpapers 2014 Page 53 133,757,467$ 34 Other Adjustments Workpapers 2014 Page 53 1,105,000 56 Total Revenue 134,862,467$

Schedule C3

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Cost of Gas Sold Schedule No.: C4For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

LineNo. Description Source Cost of Gas12 Cost of Gas:3 Energy Workpapers 2014 Page 19 71,684,716$ 4 Dem-Peak Day (D-1) - 5 Other COG - 67 Total Cost of Gas 71,684,716$

Schedule C4

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Operation and Maintenance Expenses Schedule No.: C5For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line Operation andNo. Description Source Maint. Expenses12 Production - Other:3 Energy Workpapers 2014 Page 19 777,743$ 4 Dem-Peak Day (D-1) Workpapers 2014 Page 19 518,186$ 5 Other COG 726,852$ 67 Total Production-Other 2,022,781$ 89 Operation and Maintenance Expenses:10 Transmission Workpapers 2014 Page 19 503,162$ 11 Distribution Workpapers 2014 Page 19 17,969,986 12 Storage Workpapers 2014 Page 19 930,395 13 Customer Accounts Workpapers 2014 Page 19 14,996,806 14 Customer Service Workpapers 2014 Page 19 1,094,919 15 Sales Workpapers 2014 Page 19 - 1617 Total Operation and Maintenance Expenses 35,495,268$ 1819 Total Production-Other and Operation & Maintenance Expenses 37,518,049$

Schedule C5

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Depreciation and Amortization Expense Schedule No.: C6For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line Depreciation &No. Description Source Amort. Expense12 Depreciation and Amortization Expense3 Depreciation Expense Workpapers 2014 Page 34 9,779,652$ 4 Amortization Expense - 56 Total Depreciation and Amortization Expense 9,779,652$

Schedule C6

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Taxes Other Than Income Taxes Schedule No.: C7For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line GeneralNo. Description Source Taxes12 Taxes Other Than Income Taxes34 FEDERAL5 Retirement Benefits Workpapers 2014 Page 51 668,268$ 6 Unemployment Comp Workpapers 2014 Page 51 11,802 7 PR Taxes Credited Workpapers 2014 Page 51 - 8 Super Fund Tax9 Highway Use Tax

10 Federal Excise Tax Workpapers 2014 Page 51 610 1112 STATE13 Gross Receipts Tax -$ 14 Unemployment Comp Workpapers 2014 Page 51 44,156 15 Remain. Assessment16 Use Tax 1,512 17 Unauthor Ins Tax Workpapers 2014 Page 51 14,470 18 Wis Recycling Fee19 Single Business Tax - 20 Property Workpapers 2014 Page 51 3,366,214 2122 LOCAL23 Real Est & Property2425 IBS26 IBS Payroll Tax Workpapers 2014 Page 51 397,745$ 2728 OTHER29 Franchise Tax Fees Workpapers 2014 Page 51 -$ 30 State Unitary Fees Workpapers 2014 Page 51 - 3132 Total Taxes Other Than Income Taxes 4,504,777$

Schedule C7

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Federal Income Taxes Schedule No.: C8For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line Federal IncomeNo. Description Source Taxes12 Federal Income Taxes Workpapers 2014 Page 35 2,509,208$

Schedule C8

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)State Income Taxes Schedule No.: C9For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line State IncomeNo. Description Source Taxes12 State Income Taxes Workpapers 2014 Page 35 295,743$

Schedule C9

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Other (or Local) Taxes Schedule No.: C10For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line Other (or Local)No. Description Source Taxes12 None

Schedule C10

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Allowance for Funds Used During Construction Schedule No.: C11For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

LineNo. Description Source AFUDC12 AFUDC Debt Workpapers 2014 Page 49 -$ 3 AFUDC Equity Workpapers 2014 Page 49 -$ 45 Total AFUDC -$

Schedule C11

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-3 (KAD-3)Adjusted Net Operating Income -- Income Tax Savings Schedule No.: C12For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

LineNo. Description Source TOTAL12 Rate Base Ex A-2 Sch B-1 210,493,148$ 34 Debt Portion of Capital Structure Ex A-4 Sch D-1 42.02%56 Portion of Rate Base Funded by Debt Ln 1 x Ln 2 88,451,326$ 78 Cost of Debt (1) Ex A-4 Sch D-1 4.8750%910 Interest Allowed Ln 3 x Ln 4 4,311,999$ 1112 LESS INTEREST DEDUCTION13 INCLUDED IN RECORDED14 INCOME TAX ACCRUALS:15 Gas/Jurisdictional Company Books & Records 4,299,933$ 1617 Additional Interest Allowed Ln 10 - Ln 15 12,066$ 1819 Income Tax Effect20 Current Income Tax Rate of 41.0000% 4,947$

21222324252627282930

Schedule C12

May not cross-check due to rounding

* The Cost of Debt represents the weightingof respective Short Term and Long Term

Debt amounts against total debt multipliedby their respective costs.

Source: (1) Use Capital Structure Percentagesexcluding DITC from the Total.

Case No. U-17273Exhibit A-3 (KAD-3)

Schedule C13Page 1 of 6


2012 2014 Forecasted 2014 ForecastedHistorical 2013 2014 Total O&M Total O&M

Total O&M Not Including Cost of Gas Including K&MCPI CPI K&M Adjustments K&M K&M Reason

(1) PRODUCTION EXPENSES A. Gas Steam ProductionOperation:(700) Operation Supervision & Engineering - 1.708% 1.993% - - - - (701) Operation Labor - 1.708% 1.993% - - - - (702) Boiler Fuel - 1.708% 1.993% - - - - (703) Miscellaneous Steam Expenses - 1.708% 1.993% - - - - (704) Transferred-Credit - 1.708% 1.993% - - - -

TOTAL Operation - - - - -

Maintenance:(705) Maintenance Supervision & Engineering - 1.708% 1.993% - - - - (706) Maintenance of Structures & Improvements - 1.708% 1.993% - - - - (707) Maintenance of Boiler Plant Equipment - 1.708% 1.993% - - - - (708) Maint of Oth Stm ProdPlt - 1.708% 1.993% - - - -

TOTAL Maintenance - - - - - TOTAL Production Expenses-Gas Steam - - - - -

B. Liquified Gas ProductionOperation:(710) Operation Supervision & Engineering - 1.708% 1.993% - - - - (711) Steam Expenses - 1.708% 1.993% - - - - (712) Other Power Expenses - 1.708% 1.993% - - - - (717) Petroleum Gas Expenses - 1.708% 1.993% - - - - (728) Petroleum Gas - 1.708% 1.993% - - - - (732) Purification Expenses - 1.708% 1.993% - - - - (735) Miscellaneous Production Expenses 376,862 1.708% 1.993% 390,939 - 127,247 518,186 MGP Amortization (736) Rents - 1.708% 1.993% - - - -

TOTAL Operation 376,862 390,939 - 127,247 518,186

Maintenance:(740) Maintenance Supervision & Engineering - 1.708% 1.993% - - - - (741) Maintenance of Structures & Improvements - 1.708% 1.993% - - - - (742) Maintenance of Production Equipment - 1.708% 1.993% - - - -

TOTAL Maintenance - - - - - TOTAL Production Expenses-Liquified Gas 376,862 390,939 - 127,247 518,186

Michigan Gas Utilities CorporationOperation and Maintenance Expenses - Gas Utility

Historical and Forecasted

May not cross-check due to rounding.








C. Natural Gas ProductionOperation:(754) Field Compressor Station - 1.708% 1.993% - - - - (756) Field Measuring & Regulating Station - 1.708% 1.993% - - 268,248 268,248 Company Use

TOTAL Operation - - - 268,248 268,248

Maintenance: - - - - - 1.708% 1.993% - - - -

TOTAL Maintenance - - - - - TOTAL Production Expenses-Natural Gas - - - 268,248 268,248

D. Other Gas Supply ExpensesOperation:(800) Natural Gas Well Head Purchases 1,214,808 1.708% 1.993% 1,260,182 (1,260,182) - - (804) Natural Gas City Gas Purchases 56,419,239 1.708% 1.993% 58,526,521 15,887,147 (17,542) 74,396,126 Pay-at-Risk (805) Other Gas Purchases - 1.708% 1.993% - - - - (808.1) Gas Withdrawn From Storage-Debit 21,753,370 1.708% 1.993% 22,565,869 (5,138,048) - 17,427,821 (808.2) Gas Delivered to Storage-Credit (15,124,409) 1.708% 1.993% (15,689,312) (3,658,234) - (19,347,546) (810) Gas Used for Compress Station Fuel - 1.708% 1.993% - - - - (812) Gas Used for Other Operations-Credit (186,511) 1.708% 1.993% (193,478) (74,770) - (268,248) (813) Other Gas Supply Expenses 179,523 1.708% 1.993% 186,230 (186,230) (13,942) (13,942) Pay-at-Risk

TOTAL Operation 64,256,020 66,656,012 5,569,683 (31,484) 72,194,211

Maintenance:- 1.708% 1.993% - - - -

TOTAL Maintenance - - - - - TOTAL Production Expenses-Other Gas Supply 64,256,020 66,656,012 5,569,683 (31,484) 72,194,211

TOTAL PRODUCTION EXPENSES 64,632,882 67,046,951 5,569,683 364,011 72,980,645









(2) NATURAL GAS STORAGEOperation:(814) Operation Supervision & Engineering 81,078 1.708% 1.993% 84,107 - (2,798) 81,309 Pay-at-Risk (815) Maps & Records 90 1.708% 1.993% 94 - 0 94 Pay-at-Risk (816) Wells 28,161 1.708% 1.993% 29,213 - (365) 28,848 Pay-at-Risk (817) Lines Expense 21,124 1.708% 1.993% 21,914 - (139) 21,775 Pay-at-Risk

(818) Compressor Station 15,909 1.708% 1.993% 16,504 - (131) 16,373 Pay-at-Risk

(819) Compress Station F&Pwr 83,457 1.708% 1.993% 86,575 - 70,502 157,077 Storage fields filled (820) Measuring & Regulating Station 7,133 1.708% 1.993% 7,400 - (2) 7,398 Pay-at-Risk (821) Purification Expenses 9,495 1.708% 1.993% 9,851 - (107) 9,744 Pay-at-Risk (824) Other Expenses 94,048 1.708% 1.993% 97,562 - (816) 96,746 Pay-at-Risk

TOTAL Operation 340,495 353,220 - 66,143 419,363

Maintenance:(830) Maintenance Supervision & Engineering 6,909 1.708% 1.993% 7,169 - (98) 7,071 Pay-at-Risk (832) Maintenance Reservoirs & Wells 54,804 1.708% 1.993% 56,852 - 79,958 136,810 Well Logs/ Pay-at-Risk (833) Maintenance of Lines 19,513 1.708% 1.993% 20,243 - (165) 20,078 Pay-at-Risk (834) Maintenance Compressor Station Equipment 44,118 1.708% 1.993% 45,767 - (120) 45,647 Pay-at-Risk (835) Maintenance Measuring & Regulating Equipment 5,119 1.708% 1.993% 5,311 - (85) 5,226 Pay-at-Risk (836) Maintenance Purification Equipment 3,534 1.708% 1.993% 3,667 - (46) 3,621 Pay-at-Risk (837) Maintenance Other Equipment 16,708 1.708% 1.993% 17,333 - (59) 17,274 Pay-at-Risk (842) Other Storage-Fuel 9,401 1.708% 1.993% 9,753 - - 9,753

TOTAL Maintenance 160,106 166,095 - 79,386 245,481 TOTAL Natural Gas Storage Expenses 500,601 519,315 - 145,529 664,844

(3) TRANSMISSION EXPENSESOperation:(850) Operation Supervision & Engineering 9,769 1.708% 1.993% 10,135 - - 10,135 (851) Sys Cont & Load Disp - 1.708% 1.993% - - - - (856) Mains Exp 41,602 1.708% 1.993% 43,157 - (76) 43,081 Pay-at-Risk (857) Measuring & Regulating Station 118,840 1.708% 1.993% 123,279 - (4) 123,275 Pay-at-Risk (859) Other Expenses 4,854 1.708% 1.993% 5,036 - - 5,036

TOTAL Operation 175,065 181,607 - (80) 181,527

Maintenance:(863) Maintenance of Mains 14,255 1.708% 1.993% 14,788 - (23) 14,765 Pay-at-Risk (865) Maintenance Measuring & Regulating Equipment 139,167 1.708% 1.993% 144,365 - (67) 144,298 Pay-at-Risk (867) Maintenance Other Equipment 5,382 1.708% 1.993% 5,584 - - 5,584

TOTAL Maintenance 158,804 164,737 - (90) 164,647 TOTAL Transmission Expenses 333,869 346,344 - (170) 346,174









(4) DISTRIBUTION EXPENSES Operation:(870) Operation Supervision & Engineering 1,070,518 1.708% 1.993% 1,110,503 - (55,925) 1,054,578 Pay-at-Risk (871) Distribution Load Dispatching 373,630 1.708% 1.993% 387,586 - (1,553) 386,033 Pay-at-Risk (874) Mains and Services Expenses 1,206,821 1.708% 1.993% 1,251,897 - 356 1,252,253 Pay-at-Risk (875) Measuring & Regulating Station Equipment 19,177 1.708% 1.993% 19,894 - - 19,894 (877) Measuring & Regulating Station Equipment-City Gate Check Station 67,932 1.708% 1.993% 70,471 - (1,819) 68,652 Pay-at-Risk (878) Meter & House Regulator Expense 1,103,777 1.708% 1.993% 1,145,005 - (203) 1,144,802 Pay-at-Risk (879) Customer Installations Expense 580,962 1.708% 1.993% 602,662 - (83) 602,579 Pay-at-Risk

(880) Other Expenses 2,480,376 1.708% 1.993% 2,573,020 - 238,761 2,811,781 Building Expenses/ Pay-at-

Risk (881) Rents 15,891 1.708% 1.993% 16,486 - - 16,486

TOTAL Operation 6,919,084 7,177,524 - 179,533 7,357,057

Maintenance:

(885) Maintenance Supervision & Engineering 41,664 1.708% 1.993% 43,221 - 448,460 491,681 Non-Union Staff Vacancies/

Pay-at-Risk

(887) Maintenance of Mains 652,822 1.708% 1.993% 677,206 - 248,660 925,866 High Risk Mains/ Pay-at-

Risk (889) Maintenance of Measuring & Regulating Station 52,541 1.708% 1.993% 54,505 - (65) 54,440 Pay-at-Risk (891) Maintenance of Measuring & Regulating Gate Station Equipment 61,594 1.708% 1.993% 63,896 - (360) 63,536 Pay-at-Risk (892) Maintenance of Services 331,323 1.708% 1.993% 343,699 - 8 343,707 Pay-at-Risk (893) Maintenance of Meters & House Regulators 286,425 1.708% 1.993% 297,124 - (42) 297,082 Pay-at-Risk (894) Maintenance of Other Equipment 180,081 1.708% 1.993% 186,808 - (22) 186,786 Pay-at-Risk

TOTAL Maintenance 1,606,450 1,666,459 - 696,639 2,363,098 TOTAL Distribution Expenses 8,525,534 8,843,983 - 876,172 9,720,155









(5) CUSTOMER ACCOUNTS EXPENSESOperation:(901) Supervision 395,834 1.708% 1.993% 410,619 - (50,839) 359,780 Pay-at-Risk

(902) Meter Reading Expenses 1,837,447 1.708% 1.993% 1,906,077 - 494,949 2,401,026 Union Staff Vacancies/ Pay-

at-Risk

(903) Customer Records and Collection Expenses 5,717,980 1.708% 1.993% 5,931,550 - 363,959 6,295,509 Customer Relations/

ICE2016 Costs/ Pay-at-Risk (904) Uncollectible Accounts 1,440,571 1.708% 1.993% 1,494,377 - 422,307 1,916,684 Uncollectible Accounts (905) Miscellaneous Customer Accounts Expenses 50,011 1.708% 1.993% 51,880 - (701) 51,179 Pay-at-Risk TOTAL Customer Accounts Expenses 9,441,843 9,794,503 - 1,229,675 11,024,178

(6) CUSTOMER SERVICE AND INFORMATIONAL EXPENSESOperation:(907) Supervision 593 1.708% 1.993% 617 - (68) 549 Pay-at-Risk (908) Customer Assistance Expenses 502,078 1.708% 1.993% 520,832 - (13,953) 506,879 Pay-at-Risk (909) Informational and Instructional Expenses 184,592 1.708% 1.993% 191,487 - (629) 190,858 Pay-at-Risk (910) Miscellaneous Customer Service and Informational Expenses 3,514 1.708% 1.993% 3,647 - - 3,647 TOTAL Cust. Service and Informational Expenses 690,777 716,583 - (14,650) 701,933

(7) SALES EXPENSESOperation:(911) Supervision - 1.708% 1.993% - - - - (912) Demonstrating and Selling Expenses - 1.708% 1.993% - - - - (913) Advertising Expenses - 1.708% 1.993% - - - - (916) Miscellaneous Sales Expenses - 1.708% 1.993% - - - - TOTAL Sales Expenses - - - - -









(8) ADMINISTRATIVE AND GENERAL EXPENSESOperation:

(920) Administrative and General Salaries 4,082,801 1.708% 1.993% 4,235,297 - 442,069 4,677,366 IBS Vacancy Adjustment/ Reg Affairs/ Pay-at-Risk

(921) Office Supplies and Expenses 957,283 1.708% 1.993% 993,039 - 152,463 1,145,502 Reg Affairs/ Pay-at-Risk/

A&G Loader Adj (922) Administrative Expenses Transferred-Credit - 1.708% 1.993% - - - - (923) Outside Services Employed 705,718 1.708% 1.993% 732,078 - - 732,078 (924) Property Insurance 36,242 1.708% 1.993% 37,597 - - 37,597 (925) Injuries and Damages 451,976 1.708% 1.993% 468,858 - (22,007) 446,851 Injuries & Damages

(926) Employee Pensions and Benefits 4,778,671 1.708% 1.993% 4,957,157 - (471,453) 4,485,704 Pension & Benefits/ Pay-at-

Risk (927) Franchise Requirements - 1.708% 1.993% - - - - (928) Regulatory Commission Expenses 335,955 1.708% 1.993% 348,504 - - 348,504 (929) Duplicate Charges-Cr. - 1.708% 1.993% - - - - (930) Advertising Expenses - 1.708% 1.993% - - - - (930.1) General Advertising Expenses 1,521 1.708% 1.993% 1,578 - - 1,578

(930.2) Miscellaneous General Expenses 1,232,427 1.708% 1.993% 1,278,459 - 119,810 1,398,269 Gas Management Sytem/ ICE2016 IBS Depreciation

(931) Rents 473,695 1.708% 1.993% 491,388 - - 491,388 TOTAL Operation 13,056,289 13,543,955 - 220,882 13,764,837

Maintenance:(935) Maintenance of General Plant - 1.708% 1.993% - - - - TOTAL Maintenance - - - - - TOTAL Administrative and General Expenses 13,056,289 13,543,955 - 220,882 13,764,837

TOTAL Operation and Maintenance Expenses 97,181,795 100,811,634 5,569,683 2,821,448 109,202,764


Case No.: U-17273Exhibit No.: A-3 (KAD-3)

Schedule: C14Page: 1 of 2


Line

1 $ 518,185

2 $ 376,862

3 1.708%

4 1.993%

5 3.74%

6 $ 14,076

7 $ 390,938

8 Known and Measurable Increase (Decrease) in 2014 $ 127,247

Account 735

2014 Manufactured Gas Plant Remediation Amortization

2012 Manufactured Gas Plant Remediation Amortization

Michigan Gas Utilities CorporationCalculation of Manufactured Gas Plant Remediation Amortization

Known and Measurable Adjustment

2013 Inflation

2014 Inflation

Composite Inflation

2012 Manufactured Gas Plant Remediation Amortization Inflated to 2014

Inflation on 2012 Manufactured Gas Plant Remediation




Year Expenditure Incurred 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

1 Vintage Year Costs 181,561 86,246 245,430 406,419 370,612 50,000 14,466 43,095 38,636 48,170 - 1,099,284 629,238 411,235 394,683 1,089,811 425,792 1,045,000

2 Amortization of Costs - Year 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

3 January - - - - - - - - - - 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 4 February - - - - - - - - - - 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 5 March - - - - - - - - - - 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 6 April - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 7 May - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 8 June - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 9 July - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 10 August - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 11 September - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 12 October - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 13 November - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182 14 December - - - - - - - - - 12,372 10,859 19,301 22,499 22,539 22,740 31,405 34,833 43,182

15 Annual Amortization - - - - - - - - - 111,348 130,307 231,611 269,992 270,474 272,881 376,862 417,994 518,185

16 Net Unamortized Balance - - - - - - - - - 26,790,989 27,768,965 26,352,593 25,959,836 25,039,045 23,227,975 23,276,906 22,858,911 22,340,726

17 Total Amortization for the Twelve Months Ending, December 31, 2014 518,185

18 Historical Period Amount - Twelve Months Ended, December 31, 2012 376,862

19 Increase / (Decrease) to Other O&M Expense 141,323

For the Period Ended December 31, 2012Calculation of Manufactured Gas Plant Costs

Michigan Gas Utilities Corporation




Line

1 $ 904,206

2 $ 805,975

3 1.708%

4 1.993%

5 3.74%

6 $ 30,104

7 $ 836,079


Various

2014 Inflation

Composite Inflation

Inflation on 2012 Pay-at-Risk Paid Out

2012 Pay-at-Risk Paid Out Inflated to 2014

2013 Inflation

Michigan Gas Utilities CorporationCalculation of Pay-at-Risk at TargetKnown and Measurable Adjustment

2014 Pay-at-Risk at Target

2012 Pay-at-Risk Paid Out




556-Annual Pay-at-Risk

Plan

575-Annual Pay-at-Risk Plan Affiliate Charges In

712 - Annual Pay-at-Risk

Plan True Up

IBS Amounts Allocated to

MGUC

RTs 670 & 671 -Non Union

Wage & Hourly and Exempt

RTs 672 & 673 - Non

Union Wage & Hourly and

Exempt

726 - Annual Pay-at-Risk

Plan True Up

IBS Amounts Allocated to

MGUC 2012 Actuals 2013 CPI 2014 CPI 2012 InflatedAccount

804111 -$ -$ -$ -$ -$ -$ -$ 54,195$ 54,195.19$ 1.708% 1.993% 56,219.40$ 804130 -$ -$ -$ -$ -$ -$ -$ 1,585$ 1,584.98$ 1.708% 1.993% 1,644.18$ 813000 -$ -$ -$ -$ -$ -$ -$ 13,440$ 13,440.30$ 1.708% 1.993% 13,942.30$ 814000 -$ -$ -$ -$ -$ 9,549$ -$ 717$ 10,265.94$ 1.708% 1.993% 10,649.38$ 815000 -$ -$ -$ -$ -$ 3$ -$ -$ 2.67$ 1.708% 1.993% 2.77$ 816000 -$ -$ -$ -$ -$ 1,265$ -$ -$ 1,264.75$ 1.708% 1.993% 1,311.99$ 817000 -$ -$ -$ -$ -$ 628$ -$ -$ 628.48$ 1.708% 1.993% 651.95$ 818000 -$ -$ -$ -$ -$ 576$ -$ -$ 575.83$ 1.708% 1.993% 597.34$ 820000 -$ -$ -$ -$ -$ 19$ -$ -$ 18.83$ 1.708% 1.993% 19.53$ 821000 -$ -$ -$ -$ -$ 266$ -$ -$ 266.42$ 1.708% 1.993% 276.37$ 824000 -$ -$ -$ -$ -$ 2,962$ -$ 7$ 2,968.49$ 1.708% 1.993% 3,079.36$ 830000 -$ -$ -$ -$ -$ 713$ -$ -$ 712.97$ 1.708% 1.993% 739.60$ 832000 -$ -$ -$ -$ -$ 139$ -$ -$ 138.91$ 1.708% 1.993% 144.10$ 833000 -$ -$ -$ -$ -$ 742$ -$ -$ 741.62$ 1.708% 1.993% 769.32$ 834000 -$ -$ -$ -$ -$ 428$ -$ -$ 427.54$ 1.708% 1.993% 443.51$ 835000 -$ -$ -$ -$ -$ 253$ -$ -$ 252.86$ 1.708% 1.993% 262.30$ 836000 -$ -$ -$ -$ -$ 112$ -$ -$ 111.56$ 1.708% 1.993% 115.73$ 837000 -$ -$ -$ -$ -$ 306$ -$ -$ 306.21$ 1.708% 1.993% 317.65$ 856000 -$ -$ -$ -$ -$ 287$ -$ -$ 287.29$ 1.708% 1.993% 298.02$ 857000 -$ -$ -$ -$ -$ 8$ -$ -$ 7.86$ 1.708% 1.993% 8.15$ 863000 -$ -$ -$ -$ -$ 433$ -$ -$ 433.04$ 1.708% 1.993% 449.21$ 865000 -$ -$ -$ -$ -$ 570$ -$ -$ 569.69$ 1.708% 1.993% 590.97$ 870000 -$ -$ -$ -$ -$ 110,199$ -$ 30,802$ 141,000.87$ 1.708% 1.993% 146,267.31$ 871000 -$ -$ -$ -$ -$ 2,392$ -$ 10,230$ 12,621.65$ 1.708% 1.993% 13,093.07$ 874000 -$ -$ -$ -$ -$ 3,600$ -$ -$ 3,600.00$ 1.708% 1.993% 3,734.46$ 877000 -$ -$ -$ -$ -$ 4,516$ -$ -$ 4,516.26$ 1.708% 1.993% 4,684.94$ 878000 -$ -$ -$ -$ -$ 533$ -$ -$ 533.13$ 1.708% 1.993% 553.04$ 879000 -$ -$ -$ -$ -$ 222$ -$ -$ 222.12$ 1.708% 1.993% 230.42$ 880000 -$ -$ -$ -$ -$ 22,764$ -$ 6,940$ 29,704.16$ 1.708% 1.993% 30,813.62$ 885000 -$ -$ -$ -$ -$ 199$ -$ -$ 198.82$ 1.708% 1.993% 206.25$ 887000 -$ -$ -$ -$ -$ 5,885$ -$ -$ 5,884.73$ 1.708% 1.993% 6,104.53$ 889000 -$ -$ -$ -$ -$ 184$ -$ -$ 184.28$ 1.708% 1.993% 191.16$ 891000 -$ -$ -$ -$ -$ 691$ -$ -$ 691.11$ 1.708% 1.993% 716.92$ 892000 -$ -$ -$ -$ -$ 107$ -$ -$ 107.43$ 1.708% 1.993% 111.44$ 893000 -$ -$ -$ -$ -$ 128$ -$ -$ 128.11$ 1.708% 1.993% 132.89$ 894000 -$ -$ -$ -$ -$ 72$ -$ -$ 72.48$ 1.708% 1.993% 75.19$ 901000 -$ -$ -$ -$ -$ -$ -$ 49,009$ 49,008.88$ 1.708% 1.993% 50,839.38$ 902000 -$ -$ -$ -$ -$ 2,394$ -$ 8,990$ 11,383.75$ 1.708% 1.993% 11,808.94$ 903000 -$ -$ -$ -$ -$ 33,728$ -$ 29$ 33,756.78$ 1.708% 1.993% 35,017.61$ 905000 -$ -$ -$ -$ -$ 4$ -$ 856$ 859.29$ 1.708% 1.993% 891.38$ 907000 -$ -$ -$ -$ -$ -$ -$ 66$ 65.96$ 1.708% 1.993% 68.42$ 908000 -$ -$ -$ -$ -$ 52,431$ -$ 46$ 52,476.97$ 1.708% 1.993% 54,437.01$ 909000 -$ -$ -$ -$ -$ -$ -$ 2,832$ 2,832.12$ 1.708% 1.993% 2,937.90$ 920000 -$ 9,907$ -$ 27,042$ -$ 121,121$ -$ 276,909$ 434,979.60$ 1.708% 1.993% 451,226.26$ 921000 -$ -$ -$ -$ -$ -$ -$ 2$ 1.59$ 1.708% 1.993% 1.65$ 926190 -$ -$ -$ -$ 403,175$ (471,515)$ -$ 284$ (68,056.24)$ 1.708% 1.993% (70,598.17)$

Total -$ 9,907$ -$ 27,042$ 403,175$ (91,087)$ -$ 456,938$ 805,975.28$ 836,078.78$

Accrual entries for the non-executive annual incentive plan are recorded monthly using Resource Types 670 and 671. The expense is posted using a highlevel Responsibility Center. Resource Types 672 and 673 are then used to push this gross expense out to the various accounts, following the labor loaders.Sometimes the expense going into account 926190 is not loaded out on a 1 for 1 basis, particularly when the books get opened and re-opened in mid Januaryand there's not enough time to run the loaders. The residual remains in the account and no true up is done.

Michigan Gas Utilities Corporation2012 Annual Pay-at-Risk Plan Information

Executive and Non Executive Plans Paid Out

Executives' Annual Pay-at-Risk Plan Non Executives' Annual Pay-at-Risk Plan




2012 Wage & Hour 2014 Inflated Non-Union 2014 Inflated 2012 2014 Inflated Exempt 2014 Inflated 2014 Inflated Non-Union Non-Union K&M Labor Total Base Pay-at-Risk Non-Union Exempt Exempt K&M Labor Total Base Pay-at-Risk Exempt Executive Total

Account Base Labor Base Labor Adjustments Labor Target % Pay-at-Risk Base Labor Base Labor Adjustments Labor Target % Pay-at-Risk Pay-at-Risk Pay-at-Risk-$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$

804111 98,890$ 102,584$ 102,584$ 5.00% 5,129$ 284,612$ 295,242$ 295,242$ 11.92% 35,193$ 40,322$ 804130 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 813000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 814000 13$ 14$ 14$ 5.00% 1$ 63,489$ 65,860$ 65,860$ 11.92% 7,851$ 7,851$ 815000 67$ 70$ 70$ 5.00% 3$ -$ -$ -$ 11.92% -$ 3$ 816000 18,267$ 18,950$ 18,950$ 5.00% 947$ -$ -$ -$ 11.92% -$ 947$ 817000 9,886$ 10,255$ 10,255$ 5.00% 513$ -$ -$ -$ 11.92% -$ 513$ 818000 8,984$ 9,319$ 9,319$ 5.00% 466$ -$ -$ -$ 11.92% -$ 466$ 820000 348$ 361$ 361$ 5.00% 18$ -$ -$ -$ 11.92% -$ 18$ 821000 3,254$ 3,376$ 3,376$ 5.00% 169$ -$ -$ -$ 11.92% -$ 169$ 824000 15,401$ 15,976$ 15,976$ 5.00% 799$ 11,839$ 12,281$ 12,281$ 11.92% 1,464$ 2,263$ 830000 -$ -$ -$ 5.00% -$ 5,190$ 5,384$ 5,384$ 11.92% 642$ 642$ 832000 1,303$ 1,351$ 1,351$ 5.00% 68$ 276$ 286$ 286$ 11.92% 34$ 102$ 833000 11,651$ 12,086$ 12,086$ 5.00% 604$ -$ -$ -$ 11.92% -$ 604$ 834000 6,245$ 6,478$ 6,478$ 5.00% 324$ -$ -$ -$ 11.92% -$ 324$ 835000 3,416$ 3,543$ 3,543$ 5.00% 177$ -$ -$ -$ 11.92% -$ 177$ 836000 1,335$ 1,385$ 1,385$ 5.00% 69$ -$ -$ -$ 11.92% -$ 69$ 837000 4,989$ 5,175$ 5,175$ 5.00% 259$ -$ -$ -$ 11.92% -$ 259$ 850000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 856000 4,288$ 4,448$ 4,448$ 5.00% 222$ -$ -$ -$ 11.92% -$ 222$ 857000 79$ 81$ 81$ 5.00% 4$ -$ -$ -$ 11.92% -$ 4$ 859000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 863000 7,671$ 7,957$ 7,957$ 5.00% 398$ 225$ 233$ 233$ 11.92% 28$ 426$ 865000 1,138$ 1,180$ 1,180$ 5.00% 59$ 3,759$ 3,899$ 3,899$ 11.92% 465$ 524$ 867000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 870000 5,325$ 5,524$ 5,524$ 5.00% 276$ 728,378$ 755,583$ 755,583$ 11.92% 90,065$ 90,342$ 871000 139,708$ 144,926$ 144,926$ 5.00% 7,246$ 34,728$ 36,025$ 36,025$ 11.92% 4,294$ 11,540$ 874000 4,118$ 4,272$ 4,272$ 5.00% 214$ 31,346$ 32,516$ 32,516$ 11.92% 3,876$ 4,090$ 875000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 877000 34,729$ 36,026$ 36,026$ 5.00% 1,801$ 8,607$ 8,929$ 8,929$ 11.92% 1,064$ 2,866$ 878000 839$ 871$ 871$ 5.00% 44$ 2,481$ 2,574$ 2,574$ 11.92% 307$ 350$ 879000 2,829$ 2,934$ 2,934$ 5.00% 147$ -$ -$ -$ 11.92% -$ 147$ 880000 242,612$ 251,674$ 251,674$ 5.00% 12,584$ 56,540$ 58,652$ 58,652$ 11.92% 6,991$ 19,575$ 881000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 885000 -$ -$ 101,750$ 101,750$ 5.00% 5,088$ 1,557$ 1,615$ 305,250$ 306,865$ 11.92% 36,578$ 41,666$ 887000 87,132$ 90,387$ 90,387$ 5.00% 4,519$ 1,984$ 2,058$ 2,058$ 11.92% 245$ 4,765$ 889000 2,428$ 2,519$ 2,519$ 5.00% 126$ -$ -$ -$ 11.92% -$ 126$ 891000 6,887$ 7,144$ 7,144$ 5.00% 357$ -$ -$ -$ 11.92% -$ 357$ 892000 1,190$ 1,234$ 1,234$ 5.00% 62$ 465$ 483$ 483$ 11.92% 58$ 119$ 893000 59$ 62$ 62$ 5.00% 3$ 712$ 738$ 738$ 11.92% 88$ 91$ 894000 -$ -$ -$ 5.00% -$ 426$ 442$ 442$ 11.92% 53$ 53$ 901000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 902000 16,131$ 16,733$ 16,733$ 5.00% 837$ 7,453$ 7,732$ 7,732$ 11.92% 922$ 1,758$ 903000 226,000$ 234,441$ 234,441$ 5.00% 11,722$ 117,023$ 121,394$ 121,394$ 11.92% 14,470$ 26,192$ 905000 52$ 54$ 54$ 5.00% 3$ 1,511$ 1,568$ 1,568$ 11.92% 187$ 190$ 907000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 908000 91,515$ 94,933$ 94,933$ 5.00% 4,747$ 289,017$ 299,812$ 299,812$ 11.92% 35,738$ 40,484$ 909000 -$ -$ -$ 5.00% -$ 18,671$ 19,368$ 19,368$ 11.92% 2,309$ 2,309$ 912000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 920000 659,521$ 684,154$ 684,154$ 5.00% 34,208$ 3,114,972$ 3,231,318$ 292,014$ 3,523,332$ 11.92% 419,981$ 147,093$ 601,281$ 920020 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 921000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 925000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 926190 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 926191 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 930100 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 931000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ 935000 -$ -$ -$ 5.00% -$ -$ -$ -$ 11.92% -$ -$ Total 1,718,300$ 1,782,480$ 101,750$ 1,884,230$ 94,211$ 4,785,260$ 4,963,991$ 597,264$ 5,561,255$ 662,902$ 147,093$ 904,206$

Michigan Gas Utilities Corporation2014 Annual Pay-at-Risk Plan Information

Executive and Non Executive Plans at Target




Line

1 $ 7,288,278

2 2012 Customer Relations and ICE 2016 O&M Costs $ 6,666,497

3 1.708%

4 1.993%

5 3.74%

6 Inflation on 2012 A&G Costs $ 248,996

7 2012 Customer Relations and ICE2016 O&M Costs Inflated to 2014 $ 6,915,493


Account 903

2013 Inflation

2014 Inflation

Composite Inflation

Michigan Gas Utilities CorporationCalculation of Customer Relations and ICE2016 O&M Costs


2014 Customer Relations and ICE2016 O&M Costs




Historical Total O&M Total O&MTotal O&M 2013 2014 Not Including Including

Ln Description 2012 CPI CPI K&M K&M K&M

1 Customer Relations Loaded Labor 577,313 1.708% 1.993% 598,877 (209,719) 389,158 2 Customer Relations Non-Labor 4,905,754 1.708% 1.993% 5,088,987 356,152 5,445,139 3 ICE 2016 O&M 79,074 1.708% 1.993% 82,028 225,391 307,419 4 Balance in accounts 901 903 905 907 908 1,104,356 1.708% 1.993% 1,145,605 961 1,146,566 56 Total 6,666,497 6,915,497 372,785 7,288,282


Related to Customer Relations and ICE 2016 O&M CostsCalculation of K&M Adjustment affecting Accounts 901 903 905 907 908




Line

1 $ 1,917,930

2 $ 1,440,571

3 1.726%

4 2.060%

5 3.82%

6 $ 55,052

7 $ 1,495,623

8 $ 422,307

Account 904

2013 Inflation

2014 Inflation

Composite Inflation

Inflation on 2012 Uncollectible Accounts

2012 Uncollectible Accounts Inflated to 2014

Known and Measurable Increase (Decrease) in 2014

2012 Uncollectible Accounts

Michigan Gas Utilities CorporationCalculation of Uncollectible AccountsKnown and Measurable Adjustment

2014 Uncollectible Accounts




Total Net UncollectiblesNet Gas Service as a Percent of

Line Year Write-Offs Collections Uncollectibles Revenues Revenue[P-522, Page 300]

1 2010 $2,572,225 $0 $2,572,225 $163,823,005 1.5701%2 2011 $1,707,618 $0 $1,707,618 $142,515,824 1.1982%3 2012 $1,427,896 $0 $1,427,896 (1) $93,123,234 1.5333%4 Average 1.4339%

567 Allowance for Uncollectible Expense for 201489 2014 Forecasted Revenue without rate increase $133,757,46210 3-Year Average Net Uncollectibles as a Percent of Revenue 1.43389%11 Net Uncollectibles Allowance for 2014 $1,917,93012

(1) Matches U-17222 UETM application

[P-522, Page 228A]

Michigan Gas Utilities CorporationAllowance for Uncollectibles Expense for 2014




Line

1 $ 213,581

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -

7 2012 Costs Inflated to 2014 $ -

8 $ 213,581

Account 920

2012 Costs

Inflation on 2012 Costs


2013 Inflation

2014 Inflation

Composite Inflation

2014 Costs

Michigan Gas Utilities CorporationCalculation of IBS Vacancies





Line

1 $100,085,836

2 2012 Average FTE's 1,260

3 Line 8 / Line 9 $79,433

4 1,332

5 Line 11 - Line 9 72

6 Line 10 x Line 12 $5,719,191

7 3.6%

8 Line 13 x Line 14 $205,891

9 Line 15 inflated by Lines 3 & 4 $213,581Line 14 inflated

Budgeted Average FTE's

2012 Vacancies

2012 Vacancy O&M

2012 Percentage Allocated to MGUC

2012 Vacancy O&M Allocated to MGUC

2012 Base and Overtime IBS Internal O&M

Average Base and Overtime O&M per FTE


IBS Vacancies Calculation




Line

1 $ 141,362

2 $ 60,663

3 1.708%

4 1.993%

5 3.74%

6 $ 2,266

7 2012 Costs Inflated to 2014 $ 62,928

8 $ 78,433

Account 920

2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation

2014 Costs

Michigan Gas Utilities CorporationCalculation of IBS Regulatory Affairs Increase -- Labor





Line

1 $ 146,069

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 146,069

9 Account 921

Year Actual10 2012 $189,977 11 2011 $149,121 12 2010 $126,047 13 2009 $121,191 14 2008 $144,011 15 Average $146,069

2014 Costs

Michigan Gas Utilities CorporationCalculation of A&G Loader Adjustment


2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 8,056

2 $ 1,601

3 1.708%

4 1.993%

5 3.74%

6 $ 60


8 $ 6,395

Account 920

2014 Costs

Michigan Gas Utilities CorporationCalculation of IBS Regulatory Affairs -- Non-Labor


2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 446,851

2 $ 451,976

3 1.708%

4 1.993%

5 3.74%

6 $ 16,881


8 $ (22,007)

Account 925

Year Actual9 2010 $444,81610 2011 $443,76011 2012 $451,976

12 Average $446,851

Michigan Gas Utilities CorporationCalculation of Injuries and DamagesKnown and Measurable Adjustment

2014 Injuries & Damages

2012 Injuries & Damages



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 1,563,610

2 $ 1,594,610

3 1.708%

4 1.993%

5 3.74%

6 $ 59,559

7 2012 Pension and Benefit Costs Inflated to 2014 $ 1,654,169

8 Known and Measurable Increase (Decrease) in 2014 $ (90,559)

Account 926

Michigan Gas Utilities CorporationBenefits Expense (Amortizations only)


2014 Pension and Benefit Costs


2013 Inflation

2014 Inflation

Composite Inflation

Inflation on 2012 Pension and Benefit Costs




Line

1 $ 2,851,496

2 $ 3,184,062

3 1.708%

4 1.993%

5 3.74%

6 $ 118,926

7 2012 Pension and Benefits Costs Inflated to 2014 $ 3,302,988

8 Known and Measurable Increase (Decrease) in 2014 $ (451,492)

Account 926

2013 Inflation

2014 Inflation

Composite Inflation

Inflation on 2012 Pension and Benefit Costs

Michigan Gas Utilities CorporationBenefits Expense (Less Amortizations)







Line

1 $ 119,810

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 119,810

Account 930.2

2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation

2014 Costs

Michigan Gas Utilities CorporationCalculation of IBS Depreciation Gas Management System & ICE Hardware



Page: 1 of 1Witness: Katherine A. De Cramer, CPA

Line Source Date 2013 2014

1 Value Line February 22, 2013 1.300% 1.900%2 Global Insight February, 2013 1.400% 1.700%3 Moore Inflation Predictor December 15, 2012 1.700% N/A4 EIA February, 2013 2.340% 2.380%5 International Monetary Fund October, 2012 1.800% N/A

6 MGUC Estimate (Simple Average) 1.708% 1.993%

Estimate of Inflation for 2013 and 2014Michigan Gas Utilities Corporation



Allocation Line Rate Schedule Factor (1)

1 Residential 54.6885%

2 Residential Multi-Family -- Class I 0.0807%

3 Residential Multi-Family -- Class II 0.3972%

4 Residential Multi-Family -- Class III 0.0818%

5 Residential Multi-Family -- Class IV 0.2173%

6 General Service Small 10.7453%

7 General Service Large 0.6192%

8 TR-1 3.8806%

9 TR-2 4.2115%

10 TR-3 2.7115%

11 Customer Choice - Residential 11.9579%

12 Customer Choice - Small General Service 7.1386%

13 Aggregated Transport - Residential 0.0230%

14 Aggregated Transport - Small General Service 2.9793%

15 Aggregated Transport - Large General Service 0.0683%

16 TOTAL MGUC 99.8007%

Note (1): Allocation factors do not sum to 100% because Special Contracts are not subject to the UETM.

Michigan Gas Utilities CorporationUETM Allocation Factors


Page: 1 of 2 Witness: Katherine A. De Cramer

Integrys Energy Group, Inc. Awards & Recognition: 2006-2012 2006

Integrys Energy Group: Forbes, utility industry’s “Best Managed Energy Company in America”

Integrys Energy Group: Fortune magazine, Most Admired Energy Company among “America’s Most Admired Companies”

Integrys Energy Services: MastioGale, 2nd in customer value among regional energy marketers

Upper Peninsula Power Company: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: JD Power & Associates, an “All Time Best Residential Electric

Performer”

2007 Integrys Energy Group: Fortune magazine, 2nd among Most Admired Energy Companies

in “America’s Most Admired Companies” Integrys Energy Group: Platts, finalist for Platts 250 Global Energy Companies of the Year Integrys Energy Group: Forbes 400 Best Big Companies Integrys Energy Services: KEMA, Inc., ranked 3rd for megawatt-hours under contract

among U.S. power retailers Upper Peninsula Power Company: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: E-source, wisconsinpublicservice.com ranked 3rd out of more

than 100 utility Web sites 2008

Integrys Energy Group: Platts, a Top 250 Global Energy Company Upper Peninsula Power Company: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: POWER magazine, 2008 Plant of the Year Wisconsin Public Service: Power Engineering magazine, Best Coal-Fired Project for 2008 Wisconsin Public Service: WasteCap Wisconsin, 2008 Big Diverter Award Wisconsin Public Service: Platts, finalist for Platts ENR Energy Construction Project of

the Year 2009

Integrys Energy Group: Fortune magazine, Most Admired Energy Company among “The World’s Most Admired Companies”; 8th most admired in Use of Corporate Assets; 9th most admired in Innovation; and 10th most admired in Long-Term Investment

Integrys Energy Group: Newsweek, 5th in Green Rankings of Fortune 500 Utilities. Integrys Energy Group: Platts, Top 250 Global Energy Company Integrys Energy Group: HR Executive magazine’s Most Admired Energy Company in HR Upper Peninsula Power Company: National Arbor Day Foundation, Tree Line USA Utility


Page: 2 of 2 Witness: Katherine A. De Cramer

Wisconsin Public Service/Upper Peninsula Power Company: ESource, IVR ranked 7th of

95 nationally, and 1st of 25 in the Midwest region. Wisconsin Public Service: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: ESource, website ranked 4th of 100 nationally, and 1st of 25 in

the Midwest region.

2010

Integrys Energy Group: Fortune magazine, 4th Most Admired Energy Company among “The World’s Most Admired Companies”; 3rd most admired in Social Responsibility; 4th most admired in Use of Corporate Assets; and 4th most admired in Long-Term Investment

Integrys Energy Group: Governance Metrics International overall global rating of 10. Integrys Energy Group: Forbes 20 Most Responsible Companies Integrys Energy Group: 12th in Newsweek magazine’s Green Rankings for Utilities Integrys Energy Group: Worksite Wellness Award from Wisconsin Gov. Jim Doyle Upper Peninsula Power Company: Safety Leadership award, for support of the Upper

Peninsula Safety Conference Upper Peninsula Power Company: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: National Arbor Day Foundation, Tree Line USA Utility Wisconsin Public Service: Central Wisconsin Society for Human Resource Management

local and state Workplace Diversity Award Wisconsin Public Service: Sheboygan Young Professionals’ Advocate of the Year Award Wisconsin Public Service: Wausau Chamber of Commerce Athena Award for a Divers

Workplace Wisconsin Public Service: ESource IVR & Web benchmarking results

2011

Integrys Energy Group: Governance Metrics International overall global rating of 10 Upper Peninsula Power Company: SESC Project of the Year Award from the Michigan

Conservation Districts for McClure Wisconsin Public Service: Finalist for the Ethics in Business Award presented by the

American Foundation of Counseling Services. 2012

Wisconsin Public Service: The SolarWise for Schools program was honored with the national Center for Resources Solutions’ (CRS) 2012 Best Green Power Education Outreach Program Award.

Wisconsin Public Service: “Best Facility Award” from International Society of Automation (ISA) Power Industry Division for Weston Unit 4

Wisconsin Public Service: Finalist for the Ethics in Business Award presented by the American Foundation of Counseling Services.

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-11 (KAD-7)Revenue Deficiency (Sufficiency) Schedule: A1For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

LineNo. Description Source Total12 Rate Base Exh. A-2, Sch. B1 194,076,269$ 34 Operating Income Exh. A-3, Sch. C1 9,943,80456 Overall Rate of Return Line 4 ÷ Line 2 5.1237%78 Rate of Return Exh. A-4, Sch. D1 7.1076%910 Income Requirements Line 2 x Line 8 13,794,1491112 Income Deficiency (Sufficiency) Line 10 - Line 4 3,850,3451314 Revenue Conversion Factor Exh. A-3, Sch. C2 1.63671516 Revenue Deficiency (Sufficiency) Line 12 x Line 14 6,301,860$

Schedule A1

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-12 (KAD-8)Rate Base Schedule: B1For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(b) (c)

LineNo. Source Rate Base12 Plant in Service Exh A-2, Sch B2 310,262,590$ 3 Plant Held for Future Use Exh A-2, Sch B2 04 Construction Work in Progress Exh A-2, Sch B2 4,139,1505 Total Utility Plant 314,401,740$ 67 Less: Depreciation Reserve Exh A-2, Sch B3 171,640,37089 Net Utility Plant 142,761,370$ 1011 Net Capital Lease Property 01213 Total Utility Property and Plant 142,761,370$ 1415 Less: Capital Lease Obligations 01617 Net Plant 142,761,370$ 1819 Allowance for Working Capital Exh A-2, Sch B4 51,314,8992021 Total Rate Base 194,076,269$

(a)

Description

Schedule B1

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-12 (KAD-8)Utility Plant Schedule: B2For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

MPSCLine AccountNo. Description No. Utility Plant12 Plant in service 101 300,416,451$ 3 Plant purchased or sold 102 - 4 Plant leased to others 104 - 5 Completed construction not classified 106 6,244,378 6 Gas Stored Base Gas 117 3,601,761 7 Plant in Service 310,262,590$ 89 Plant held for future use 1051011 Construction work in progress 107 4,139,150 1213 Total Utility Plant 314,401,740$

Schedule B2

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-12 (KAD-8)Accumulated Provision for Depreciation Schedule: B3For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b)

Line Accum. Prov.No. Description Source for Depr.12 Workpapers 2012 Page 10 171,640,370$

Schedule B3

Total Accumulated Provision for Depreciation

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-12 (KAD-8)Working Capital Schedule: B4For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b)

Line WorkingNo. Description Source Capital12 Assets3 Utility Plant-ARO Workpapers 2012 Page 77 1,381,582$ 4 Accumulated Depreciation-ARO Workpapers 2012 Page 77 (271,047) 5 Cash/Bank Balance Workpapers 2012 Page 16 664,732 6 Temporary Cash Workpapers 2012 Page 82 3,937,471 7 Notes Receivable Workpapers 2012 Page 82 (662) 8 Customer A/R Workpapers 2012 Page 85 12,828,862 9 Other A/R Workpapers 2012 Page 85 471,928 10 Accumulated Provision Uncollectible Accounts Workpapers 2012 Page 85 (1,601,710) 11 Accounts Receivable from Associated Companies Workpapers 2012 Page 85 33,621 12 Taxes Receivable Other Companies Workpapers 2012 Page 85 - 13 Prepayments Workpapers 2012 Page 15 471,257 14 Accrued Utility Revenues Workpapers 2012 Page 85 6,697,946 15 Fuel Stock/Gas Storage Workpapers 2012 Page 11 16,547,698 16 Other Materials & Supplies Workpapers 2012 Page 11 488,152 17 Miscellaneous and Accrued Workpapers 2012 Page 85 2,225,382 18 Derivative Assets Workpapers 2012 Page 85 515,834 19 Int & Div Receivable Workpapers 2012 Page 85 16 20 Other Deferred Debits not in Ratebase Workpapers 2012 Page 89 67,826,186 2122 Total Assets 112,217,248$ 2324 Liabilities25 Accum Prov for Injuries & Damages Workpapers 2012 Page 96 13,496$ 26 Def Cr-Sup Ret Sel SERP Workpapers 2012 Page 95 17,027,797 27 Asset Retirement Obligation Workpapers 2012 Page 103 1,648,019 28 Accounts Payable Workpapers 2012 Page 104 14,611,043 29 Accounts Payable Other Workpapers 2012 Page 106 2,872,384 30 Accrued Taxes Workpapers 2012 Page 17 1,780,223 31 Accrued Interest Workpapers 2012 Page 108 14,006 32 Tax Collections Payable Workpapers 2012 Page 110 (143,735) 33 Miscellaneous Current/Accrued Workpapers 2012 Page 111 1,927,215 34 Derivative Liab Workpapers 2012 Page 112 75,034 35 Other Deferred Credits Workpapers 2012 Page 113 20,367,691 36 Other Regulatory Liabilities Workpapers 2012 Page 115 709,176 37 Accumulated Deferred Taxes N/A - 3839 Total Liabilities 60,902,349$ 4041 Total Working Capital 51,314,899$

Schedule B4

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Net Operating Income Schedule: C1For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b)

NetLine OperatingNo. Description Source Income12 Operating Revenues Exh. A-3, Sch. C3 122,621,203$ 34 Operating Expenses5 Cost of Gas Exh. A-3, Sch. C4 63,534,0066 Operations and Maintenance Expenses Exh. A-3, Sch. C5 33,647,7917 Depreciation and Amortization Exh. A-3, Sch. C6 8,115,3758 General Taxes Exh. A-3, Sch. C7 4,264,0759 Income Taxes Exh. A-3, Sch. C8, C9 & C10 3,068,19810 Total Operating Expenses 112,629,445$ 1112 Operating Income 9,991,758$ 1314 Operating Income Adjustments15 Allowance For Funds Used During Construction - 016 Loss on Reacquired Securities - 017 Interest - 018 Income Tax Effect of Interest Exh. A-13, Sch. C12 47,95419 Interest Synchronization Adjustment 020 Total Operating Income Adjustments 47,954$ 2122 Adjusted Net Operating Income 9,943,804$

Schedule C1

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Revenue Conversion Factor Schedule No.: C2


(a) (b) (c) (d)

Line Calc.

No. Description Logic 2012

12 Income Before Income Taxes 100.000%34 Michigan Corporate Income Tax Rate 6.0000%56 Federal Income Tax Base Ln 2 - Ln 4 94.000%78 Times Federal Income Tax Rate 35.000%910 Federal Income Tax Ln 6 x Ln 8 32.900%1112 Income After Taxes Ln 6 - Ln 10 61.100%1314 Gross Revenue Conversion Factor Ln 2 / Ln 12 1.6367

Schedule C2

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Sales Revenue Schedule No.: C3For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line SalesNo. Description Source Revenue12 Present Revenues Workpapers 2012 Page 53 115,653,998$ 34 Other Adjustments Workpapers 2012 Page 53 6,967,205 56 Total Revenue 122,621,203$

Schedule C3

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Cost of Gas Sold Schedule No.: C4For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

LineNo. Description Source Cost of Gas12 Cost of Gas:3 Energy Workpapers 2012 Page 19 63,534,006$ 4 Dem-Peak Day (D-1) - 5 Other COG - 67 Total Cost of Gas 63,534,006$

Schedule C4

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Operation and Maintenance Expenses Schedule No.: C5For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line Operation andNo. Description Source Maint. Expenses12 Production - Other:3 Energy Workpapers 2012 Page 19 722,015$ 4 Dem-Peak Day (D-1) Workpapers 2012 Page 19 376,862$ 5 Other COG 858,934$ 67 Total Production-Other 1,957,811$ 89 Operation and Maintenance Expenses:10 Transmission Workpapers 2012 Page 19 535,236$ 11 Distribution Workpapers 2012 Page 19 16,344,594 12 Storage Workpapers 2012 Page 19 755,799 13 Customer Accounts Workpapers 2012 Page 19 12,718,175 14 Customer Service Workpapers 2012 Page 19 1,336,176 15 Sales Workpapers 2012 Page 19 - 1617 Total Operation and Maintenance Expenses 31,689,980$ 1819 Total Production-Other and Operation & Maintenance Expenses 33,647,791$

Schedule C5

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Depreciation and Amortization Expense Schedule No.: C6For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line Depreciation &No. Description Source Amort. Expense12 Depreciation and Amortization Expense3 Depreciation Expense Workpapers 2012 Page 34 8,115,375$ 4 Amortization Expense - 56 Total Depreciation and Amortization Expense 8,115,375$

Schedule C6

Michigan Public Service Commission Case No.: U-17273

Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)

Taxes Other Than Income Taxes Schedule No.: C7

For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line GeneralNo. Description Source Taxes

12 Taxes Other Than Income Taxes34 FEDERAL5 Retirement Benefits Workpapers 2012 Page 51 637,759$ 6 Unemployment Comp Workpapers 2012 Page 51 11,263 7 PR Taxes Credited Workpapers 2012 Page 51 (97) 8 Super Fund Tax9 Highway Use Tax10 Federal Excise Tax Workpapers 2012 Page 51 709 1112 STATE13 Gross Receipts Tax14 Unemployment Comp Workpapers 2012 Page 51 42,140 15 Remain. Assessment16 Use Tax Workpapers 2012 Page 51 45 17 Unauthor Ins Tax Workpapers 2012 Page 51 13,270 18 Wis Recycling Fee19 Single Business Tax - 20 Property Workpapers 2012 Page 51 3,205,383 2122 LOCAL23 Real Est & Property2425 IBS26 IBS Payroll Tax Workpapers 2012 Page 51 353,472$ 2728 OTHER28 Franchise Tax Fees Workpapers 2012 Page 51 125$ 29 State Unitary Fees Workpapers 2012 Page 51 6 3031 Total Taxes Other Than Income Taxes 4,264,075$

Schedule C7

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Federal Income Taxes Schedule No.: C8For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line Federal IncomeNo. Description Source Taxes12 Federal Income Taxes Workpapers 2012 Page 35 2,868,188$

Schedule C8

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)State Income Taxes Schedule No.: C9For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line State IncomeNo. Description Source Taxes12 State Income Taxes Workpapers 2012 Page 35 200,010$

Schedule C9

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Other (or Local) Taxes Schedule No.: C10For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line Other (or Local)No. Description Source Taxes12 None

Schedule C10

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Allowance for Funds Used During Construction Schedule No.: C11For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

LineNo. Description Source AFUDC12 AFUDC Debt Workpapers 2012 Page 49 -$ 3 AFUDC Equity Workpapers 2012 Page 49 -$ 45 Total AFUDC -$

Schedule C11

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-13 (KAD-9)Adjusted Net Operating Income -- Income Tax Savings Schedule No.: C12For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

LineNo. Description Source TOTAL12 Rate Base Ex A-2 Sch B-1 194,076,269$ 34 Debt Portion of Capital Structure Ex A-4 Sch D-1 43.52%56 Portion of Rate Base Funded by Debt Ln 1 x Ln 2 84,455,394$ 78 Cost of Debt (1) Ex A-4 Sch D-1 6.1432%910 Interest Allowed Ln 3 x Ln 4 5,188,227$ 1112 LESS INTEREST DEDUCTION13 INCLUDED IN RECORDED14 INCOME TAX ACCRUALS:15 Gas/Jurisdictional Company Books & Records 5,071,266$ 1617 Additional Interest Allowed Ln 10 - Ln 15 116,961$ 1819 Income Tax Effect20 Current Income Tax Rate of 41.0000% 47,954$

21222324252627282930

Schedule C12

May not cross-check due to rounding

* The Cost of Debt represents the weightingof respective Short Term and Long TermDebt amounts against total debt multiplied

by their respective costs.

Source: (1) Use Capital Structure Percentagesexcluding DITC from the Total.

STATE OF MICHIGAN



DIRECT TESTIMONY AND EXHIBITS

MATTHEW M. DIRKSEN

FOR


June 7, 2013

1

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS

OF MATTHEW M. DIRKSEN

PART I

Q. Please state your name, position and business address. 1

A. My name is Matthew M. Dirksen. My business address is Integrys Energy Group, 2

Inc. (“Integrys”), 700 North Adams Street, P.O. Box 19001, Green Bay, WI 54307-3

9001. I am employed by Integrys Business Support, LLC (“IBS”) as a Senior Sales 4

and Revenue Forecaster in the Budget Planning and Analysis Department of 5

Integrys. I am testifying on behalf of Michigan Gas Utilities Corporation (“MGUC”), 6

which is a wholly-owned subsidiary of Integrys. Integrys resulted from the February 7

21, 2007 merger between WPS Resources Corporation and Peoples Energy 8

Corporation. 9

10


A. I hold a Bachelors Degree from the University of Wisconsin La Crosse in Accounting 12

and Psychology. I graduated May 2001. I completed my Executive MBA from UW –13

Madison in 2010. Before coming to Integrys, I worked for Kohl’s Corporate Office 14

where 3 of my 7 years were in sales forecasting. My employment started with 15

Integrys in November 2011. 16

17

18

2


A. Yes, I have submitted testimony before the Michigan Public Service Commission 2

(“MPSC”) in Gas Cost Recovery (“GCR”) proceedings in Case Nos. U-16920 and U-3

17130, regarding load forecasting. 4

3

MATTHEW M. DIRKSEN DIRECT TESTIMONY

PART II


A. The purpose of my pre-filed direct testimony is to provide an explanation of the 2

methodology used to develop MGUC’s weather normalization procedure, sales 3

forecast, and fixed charge count forecast for the 2014 projected test year. In 4

addition, I provide testimony to support a revised weather normalization period 5

moving from 30 years to 15 years. 6

7


A. Yes, I am. I am sponsoring: 9

1. Exhibit A-5 (MMD-1), Schedule E1 10

2. Exhibit A-5 (MMD-1), Schedule E1.1 11





7. Exhibit A-15 (MMD-2), Schedule E1.1 16


18



21

Q. Please describe Exhibit A-5 (MMD-1), Schedule E1. 22

A. Exhibit A-5 (MMD-1), Schedule E1 is MGUC’s sales forecast for the years 2013 – 23

2017, and is included here to comply with the filing requirements of the 24

Commission’s Orders dated December 23, 2008 and February 20, 2009 issued in 25

4

Case No. U-15895. 1

2

Q. Please describe Exhibit A-5 (MMD-1), Schedules E1.1. 3

A. Exhibit A-5 (MMD-1), Schedule E1.1 is MGUC’s 2014 projected test year sales 4

forecast using a 30 year weather normalization period. 5

6

Q. Please describe Exhibit A-5 (MMD-1), Schedules E2. 7

A. Exhibit A-5 (MMD-1), Schedule E2 is MGUC’s 2014 projected test year fixed charge 8

count forecast. 9

10


A. Exhibit A-5 (MMD-1), Schedule E3 is MGUC’s Weather Normalization study which 12

compares six alternative moving average weather normalized Heating Degree Days 13

(“HDD”) to actual degree days, and determines that a 15 year weather normalization 14

period is most accurate. 15

16


A. Exhibit A-5 (MMD-1), Schedule E4, page 1 is MGUC’s 2014 projected test year sales 18

forecast using a 15 year weather normalization period. Exhibit A-5 (MMD-1), 19

Schedule E4, page 2 depicts the difference in sales using a 15 year weather 20

normalization period compared to a 30 year weather normalization period. 21

22


A. Exhibit A-5 (MMD-1), Schedule E5 depicts the difference in revenues at present 24

rates using a 15 year weather normalization period compared to a 30 year weather 25

normalization period. 26

27

5

Q. Please describe Exhibit A-15 (MMD-2), Schedule E1.1. 1

A. Exhibit A-15 (MMD-2), Schedule E1.1 is MGUC’s 2012 historic test year sales. 2

3

Q. Please describe Exhibit A-15 (MMD-2), Schedule E2. 4

A. Exhibit A-15 (MMD-2), Schedule E2 is MGUC’s 2012 historic test year fixed charge 5

counts. 6

7

Q. Please explain how the MGUC’s 2014 projected test year sales forecast was 8

developed. 9

A. MGUC’s 2014 projected test year sales forecast was developed in MetrixND, and is 10

included here as Exhibit A-5 (MMD-1), Schedule E1.1. MetrixND is a statistical 11

software package developed by Itron, a utility consulting firm. 12

13

The forecast models in general use the regression analysis of the Ordinary Least 14

Squares method (“OLS”), with Seasonal Moving Average (“SMA”), Seasonal 15

Autoregressive (“SAR”), and Moving Average (“MA”), when necessary. These 16

models are well suited for data with seasonal and cyclical components, like utility 17

sales. 18

19

Monthly historical data were available from January 2007 through October 2012. 20

The explanatory variables employed in this forecast are: 21

1. HDD variables, 22 23

2. Trend variables, 24 25

3. Economic variables purchased from Moody’s Analytics in November 26 2012, and 27

28 4. Demographic variables. 29

30

31

6

Q. Please explain how normal weather was defined. 1

A. Normal weather was defined as the average over the 30 year period 1982-2011. 2

This resulted in 6,354 Normal HDDs, using a base temperature of 65°F. 3

4

Q. Please explain the development of the weather data. 5

Development of the 30 year normal weather data for four Michigan weather stations 6

(Benton Harbor, Coldwater, Grand Rapids, and Monroe) was derived from the hourly 7

temperatures purchased from Telvent DTN. These weather stations are all official 8

National Oceanic and Atmospheric Administration (“NOAA”) or National Weather 9

Service (”NWS”) weather stations. 10

11

The data from the individual weather stations were weighted to create variables for a 12

“virtual weather station” representative of the overall weather for the MGUC service 13

territory. 14

15

The weights were developed by first taking a snapshot of the number of customers 16

by zip code as of October 2012. The customers included were Residential, Multiple 17

Family, Small and Large Commercial/Industrial firm customers, Transport and Gas 18

Light. Based on zip code, customers were tallied by city and then each city was 19

assigned to a weather station based on the proximity to a particular weather station. 20

The weights were then calculated by taking the number-of-customers assigned to 21

each weather station divided by the total number-of-customers. The resulting 22

weights were: 23

Benton Harbor: 37% 24

Coldwater: 17% 25

Grand Rapids: 17% 26

Monroe: 29% 27

7

Actual Degree Days were calculated based on the hourly temperature data for each 1

weather station, summing up to a daily actual temperature, calculating the Degree 2

Day (“DD”) per day, applying the weight per weather station to create the “virtual 3

weather station” and summing to a total day and monthly actual HDD temperature. 4

The HDD equals the maximum of {0 or (65°F – 24-hour average temperature)}. 5

6

The calculation of normal DDs uses the actual “virtual weather station” DD and 7

averages for the years selected in creating the Normal Weather period. 8

9

Q. Please explain the procedure used to develop the weather normalized 10

adjustment to sales. 11

A. The weather normalized sales is based on a mathematical model that uses the daily 12

average of the actual sales of July and August of the previous year, then multiplies 13

those daily average sales by the number of days in a given month to arrive at the 14

Total Base Load. The Total Base Load is then subtracted from actual monthly sales 15

to give the Weather Sensitive Sales. The Weather Sensitive Sales are then divided 16

by actual number of HDD to give the Weather Sensitive use per DD. The final total 17

Weather Normalized Sales are the Weather Sensitive use per DD multiplied by the 18

normal number of HDD for that month. The final Weather Sensitive Sales will equal 19

actual sales if the Weather Adjustment is zero. 20

21

Q. Please explain how the forecast was developed. 22

A. For rate classes that have Customer Choice and General Service customers 23

(Residential, Multiple Family, and Small General Service), the models were run for 24

the entire service territory by the rate class. 25

26

27

8

Q. Please expand on how Customer Choice is accounted for in the models. 1

A. First, all customers and usage, regardless if they were Customer Choice or General 2

Service (“GS”), were summed for Residential, Multiple Family and Small General 3

Service, respectively. These values were then used as the historical values for the 4

models in MetrixND. For example, in the Residential class all the Customer Choice 5

and GS customers and usages were added together to create an aggregated service 6

territory total for customers and usages. This allows all customers in Residential to 7

have the same use-per-customer. The Customer Choice customer forecast for both 8

Residential and Small General Service was based on the average growth rates of 9

customers moving to Customer Choice between April 2012 and September 2012. 10

This average growth rate for Residential Customer Choice was about 7.6%, while 11

Small General Service Customer Choice was about 1.4%. Data prior to April 2012 12

was not considered for Residential and Small General Service due to the volatility by 13

month. Both Residential and Small General Service Customer Choice customer 14

counts are forecasted to grow based on these averages. Recent growth rates have 15

not been increasing as rapidly as the past few years. The forecast for each sector 16

was developed as described below: 17

18

Residential Model 19 The Residential forecast used two regression models, a number-of-customers model 20

and a use-per-customer model. The number-of-customers model used the MGUC’s 21

service territory population as an explanatory variable to predict the number of 22

customers. The explanatory variables employed in the use-per-customer model 23

include weather HDD base of 60°F and a trend variable. 24

25

The number-of-customers model produced an increasing customer growth of an 26

average compound growth rate (“ACGR”) of 0.4% from 2012 to 2016. 27

28

9

The use-per-customer model produced an increasing use-per-customer growth rate 1

of 0.1% ACGR from 2012 to 2016. The growth rate from 2012 to 2016 is increasing 2

or flat due to 2012 being the starting point in this calculation. The MGUC service 3

territory had a very warm winter in 2012, which kept the use per customer low. 4

5

Multi-Family Model 6 The Multi-Family forecast used two regression models, a number-of-customers 7

model and a use-per-customer model. Both are monthly models. The number-of-8

customers model used the MGUC’s service territory population as an explanatory 9

variable to predict the number of customers. The explanatory variables employed in 10

the use-per-customer model include price, household size, household income, 11

weather HDD base of 60°F. 12

13

The number-of-customers model produced a decreasing customer growth rate of 14

-0.3% from 2012 to 2016. 15

16

The use-per-customer model produced an increasing growth rate of 0.6% ACGR 17

from 2012 to 2016. The growth rate is increasing due to 2012 being the starting 18

point in this calculation. The MGUC service territory had a very warm winter in 2012, 19

which kept the use per customer low. 20

21

Small General Service Model 22 The Small General Service forecast used two regression models, a number-of-23

customers model and a use-per-customer model. Both are monthly models. The 24

number-of-customers model used the MGUC’s service territory employment as an 25

explanatory variable to predict the number-of-customers. The explanatory variables 26

employed in the use-per-customer model include weather HDD base of 60°F, MGUC 27

gross county product, price, and efficiency trends. 28

10

1

The number-of-customers model produced a decreasing customer growth rate of 2

-0.5% ACGR from 2012 to 2016. 3

4

The use-per-customer model produced an increasing growth rate of 0.7% ACGR 5

from 2012 to 2016. The growth rate is increasing due to 2012 being the starting 6

point in this calculation. The MGUC service territory had a very warm winter in 2012, 7

which kept the use per customer low. 8

9

Large General Service Model 10 The Large General Service forecast was based on a total-sales model only. The 11

explanatory variables employed in the total-sales model include MGUC’s service 12

territory employment and HDD base of 60°F. The model produced a decrease in 13

both customer counts and total sales. The customer counts will decrease 6 14

customers from 2012 to 2016, while total sales will decrease by 22,795 Mcf’s, or 15

-1.8% ACGR. 16

17

Transportation Forecast 18 The Transportation Forecast for 2013-2015 was conducted by MGUC’s Field 19

Representatives on a customer-by-customer basis with input from the customers. 20

They compiled and reviewed all Transportation customers’ data. They identified 21

which customers would be changing rate classes due to new rate structures. 22

Additionally, they identified known changes of load additions/reductions based on 23

any recent conversations with customers. After taking into account what was 24

performed previously, the representatives then reviewed the account and compared 25

the previous forecasts with actual results. 26

27

11

For 2013 the forecasted sales are increasing when compared to the actual data from 1

2012 due to increased production at some plants and new customers expected to 2

come onto the system throughout the forecast horizon. 3

4

Reasons for Overall Increase in Sales 5 Q. Please summarize why MGUC’s 2014 projected test year sales are forecasted 6

to increase when compared to the 2012 historic test year. 7

A. There are several reasons. The economy in Michigan is improving since the 8

recession ended. The unemployment rate is decreasing while the population in 9

MGUC’s territory is expected to increase. Also, the 2012 weather was abnormally 10

warm, and the forecast is projecting that the weather will return to normal trends. 11

Since MGUC implemented its most recent rate structure in January 2010, there has 12

been significant movement between rate classes. Customers have continued to 13

move from GCR Sales to the Gas Customer Choice over the last year. Although this 14

does not explain the increase in total sales, it helps to explain the rapid decline in 15

GCR volumes and the rapid increase in Gas Customer Choice volumes. 16

17

Fixed Charge Forecast 18 Q. Please explain the procedures used to develop fixed charge counts for the 19

2014 projected test year. 20

A. January – December 2012 actual fixed charge counts were used as the basis for the 21

2014 projected test year fixed charge counts. This year was selected because it had 22

the most current mix of GCR Sales and Gas Customer Choice customers. 23

24

The forecasted customer counts are allocated to the tariff level using ratios. At the 25

completion of the allocation process, immaterial differences between the fixed 26

charge counts and the forecasted fixed charge counts exist due to rounding. 27

28

12

The 2014 projected test year fixed charge count is shown on Exhibit A-5 (MMD-1), 1

Schedule E2. 2

3

Q. Please explain how revenues were developed. 4

A. Revenues were developed by multiplying the current approved tariff rate factors by 5

the forecasted sales and fixed charge counts. 6

7

Adjust Weather Normalization Period from 30 Years to 15 Years 8 Q. What time period for weather normalization does MGUC propose? 9

A. MGUC is proposing that the weather normalization period be modified from a 30 year 10

period to a 15 year period for all ratemaking and GCR purposes. The Commission 11

has previously approved a change for the gas businesses of Consumers Energy 12

Company in Case No. U-15986, SEMCO Energy Gas Company in Case No. U-13

16169, and Michigan Consolidated Gas Company in Case No. U-15701. MGUC has 14

filed its 2013-2014 GCR filing using a 15 year weather normalization period in Case 15

No. U-17130. 16

17

Q. Why is the period used for normal weather significant? 18

A. Temperature greatly impacts the amount of natural gas a customer uses in a given 19

period. Historical test year actual data must be adjusted for weather to eliminate the 20

impact of abnormal weather. This puts the actual data and the forecast data on the 21

same weather basis. Finally, normal weather is used to predict weather during the 22

forecasted period. The more accurately MGUC can predict HDD’s, the more 23

accurately it can forecast demand, which leads to optimal planning and reduces 24

costs to be recovered from customers. 25

26

Q. What historical period has MGUC traditionally used to calculate normal 27

weather? 28

13

A. MGUC has historically used a 30 year weather normalization period, and a 30 year 1

weather normalization period was used to calculate the revenue deficiency in the 2

instant general rate case. 3

4

Q. Please explain why a 15 year weather normalization period is being proposed? 5

A. The purpose of forecasting is to accurately predict future sales and revenues for 6

MGUC. Upon analysis of weather data, MGUC is proposing a 15 year weather 7

normalization period instead of the traditional 30 year weather normalization period. 8

9

Q. What analysis was performed to determine that a 15 year normal is 10

appropriate? 11

A. The common forecasting technique of using the average of historical outcomes to 12

predict future outcomes was employed. In this case, the average of historical annual 13

HDD was used to predict weather for the test year. For this analysis, six alternative 14

weather normalization periods were evaluated all which used data through 2012: 30 15

years, 25 years, 20 years, 15 years, 10 years, and 5 years. Next, the six yearly 16

average HDDs were compared to the actual HDDs by year to determine what the 17

average absolute difference back to 1993. Then, the standard deviation was 18

calculated for the absolute difference. Finally, a statistical comparison of predictive 19

capability of these time horizons was used to determine which time period was more 20

accurate, by calculating and comparing the root mean squared error (“RMSE”). 21

22

Q. Please describe how HDD data was analyzed. 23

A. The yearly historical HDD actual data was gathered for the “virtual weather station” 24

of MGUC’s service territory from 1963 to 2012. Historical data was purchased from 25

Telvent DTN. A series of moving averages for the six alternatives being studied 26

were calculated and compared with the actual HDDs observed one year later. For 27

14

example, the 15 year HDD and 30 year HDD averages for 1996 was compared with 1

the actual HDD for 1997. This process was repeated for each year from 1993 to 2

2012, the most recent year for which actual data is available. The averages and 3

standard deviations of each data set were analyzed; in both cases, the lowest value 4

reflects the most accurate HDD forecast or “normal”. The detailed analysis is 5

included in Exhibit A-5 (MMD-1), Schedule E3, Page 1 of 2. 6

7

Q. How did the 30, 25, 20, 15, 10, and 5 year HDD averages compare to actual 8

data? 9

A. Exhibit A-5 (MMD-1), Schedule E3, Page 1 of 2 summarizes MGUC’s “virtual 10

weather station” HDDs as moving averages. Column 2 depicts the actual number of 11

HDDs by year. Column 3, 5, 7, 9, 11, and 13 are the moving averages of the 12

depicted years in each column. The absolute difference columns compare the 13

moving average HDDs to the actual HDDs of that given year and is represented in 14

columns 4, 6, 8, 10, 12, and 14. 15

16

Q. What conclusions were drawn from this analysis? 17

A. This data revealed that using the average of the absolute difference, the 15 year 18

average HDDs is the most accurate and stable predictor of the next year’s actual 19

weather, see Exhibit A-5 (MMD-1), Schedule E3, Page 1 of 2, Lines 22 and Line 24. 20

The 15 year average HDDs was first in absolute difference and RSME. The 20 year 21

average HDDs was the next closest time period based on absolute difference, while 22

30 year average HDDs and 5 year average HDDs were the least accurate using the 23

same tests. 24

25

Q. How else were the predictive capabilities of the averages compared? 26

A. A statistical analysis was conducted to compare the predictive capabilities of the 27

15

average year HDDs. The first employed was the standard statistic RMSE, which is 1

widely used to measure the accuracy of forecasts. It represents the degree to which 2

the forecasted value differs from the actual data and is a measure of variance. The 3

smaller the RMSE, the smaller the overall differences between the actual and the 4

forecasted HDDs. The formula for RMSE is: 5

( )∑=

−=n

i

Eii HDDHDD

nRMSE

1

21 6

The i denotes the year of the observation, n denotes the total number of years (i.e. 7

15), HDDi refers to actual values, and EiHDD is the forecasted HDD or ‘normal’. 8

( )Eii HDDHDD − , therefore, measures the difference between actual and forecasted 9

value. 10

11

Q. Please describe your results. 12

A. Based on the MGUC virtual weather station’s historical data, a 15 year HDD average 13

outperforms a 30 year HDD average in predicting weather one year into the future. 14

As a forecasting instrument, the 15 year HDD average tends to produce a more 15

accurate forecast than the 30 year HDD average. Based on the RMSE test, as seen 16

in Table 1 below, the errors of the 30 year HDD average are significantly greater 17

than that of the 15 year HDD average. This calculation can be found on Exhibit A-5 18

(MMD-1), Schedule E3, Page 2 of 2. 19

Table 1 20

Historical Weather Analysis of HDD Average 21

HDD Average RMSE Order 22

30 Year 463.62 5 23 25 Year 449.18 4 24 20 Year 436.26 2 25 15 Year 421.02 1 26 10 Year 445.45 3 27 5 Year 476.88 6 28 29

16

Q. Please summarize why a 15 year weather normalization period was selected 1

over the other tested periods. 2

A. A 15 year weather normalization period was selected because 15 year normal HDDs 3

best predicted weather one year into the future in two of the three statistical tests, 4

average of absolute difference and RSME, while being third in standard deviation. 5

6

Weather Normal Effects on Forecast 7 Q. Has MGUC developed a sales forecast using a 15 year weather normalization 8

period? 9

A. Yes. Exhibit A-5 (MMD-1), Schedule E4, Page 1 depicts the monthly sales volumes 10

for the 2014 projected test year using a 15 year weather normalization period. 11

Further, Exhibit A-5 (MMD-1), Schedule E4, Page 2 depicts the decrease in monthly 12

sales 2014 projected test year using a 15 year weather normalization period as 13

compared to a 30 year weather normalization period. In total, sales decrease by 14

493,099 Mcf. 15

16

Q. What is the impact of using a 15 year weather normalization period on fixed 17

charge counts? 18

A. There is no change in the fixed charge counts forecast. Weather is not used as a 19

variable in forecasting this type of count. 20

21

Q. Has MGUC determined the impact on Revenues on Present Rates when using 22

a 15 year weather normalization period as compared to a 30 year weather 23

normalization period? 24

A. Yes, they have. Exhibit A-5 (MMD-1), Schedule E5, depicts the monthly volumetric 25

revenues using a 30 year weather normalization period, a 15 weather normalization 26

period, and the difference between 30 years and 15 years. In total, revenues 27

decrease by $722,363, or 2.59%, when using a 15 year weather normalization 28

17

period. 1

2

Q. Does this complete your pre-filed direct testimony? 3

A. Yes, it does. 4

Case No.: U-17273Exhibit No.: A-5 (MMD-1)

Schedule: E1Page: 1 of 2

Witness: Matthew M. Dirksen

Michigan Public Service CommissionMichigan Gas Utilities CorporationAnnual Service Area Sales by Major Customer Classes and System Output5-Year Projected

Mcf-Calendar Sales

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Losses Losses SystemLine % of OutputNo. Year Residential Commercial Industrial Transportation Company Use Total Mcf Output Unit of Measure12 2013 11,268,139 3,183,268 312,001 15,111,311 53,180 29,927,899 38,408 0.1286% Mcf3 2014 11,208,158 3,116,742 306,249 15,374,163 53,414 30,058,726 38,575 0.1286% Mcf4 2015 10,971,687 3,057,077 303,293 15,621,700 53,321 30,007,078 38,509 0.1286% Mcf5 2016 10,736,001 3,012,726 302,907 15,857,011 53,241 29,961,886 38,451 0.1286% Mcf6 2017 10,490,949 2,971,850 300,993 15,907,706 52,818 29,724,315 38,146 0.1286% Mcf

Note 1: Residential = Residential General and Heating, all Lighting, and all Multiple FamilyNote 2: Commercial = Small C&I General and Heating.Note 3: Industrial = Large C&I General and Heating, and Special Contract.Note 4: Transportation = TR-1, TR-2 and TR-3; all Aggregated Customers, and all Choice Customers

Annual Sales

Schedule E1




Michigan Public Service CommissionMichigan Gas Utilities CorporationAnnual Service Area Sales by Major Customer Classes and System Output5-Year Projected

Mcf-Calendar Sales

(k) (l) (m) (n)

LineNo. Year Residential GCC Commercial GCC Total12 2013 2,257,318 2,037,923 4,295,2423 2014 2,447,436 2,056,577 4,504,0134 2015 2,613,621 2,083,578 4,697,2005 2016 2,810,115 2,122,396 4,932,5116 2017 2,863,604 2,119,601 4,983,206

Note 5: Residential GCC = Residential Customer Choice and Multiple Family ChoiceNote 6: Commericial GCC = Small General Customer ChoiceNote 7: These Choice Sales are included in the Transportation Sales on Page 1 of 2

Schedule E1


Schedule: E1.1Page: 1 of 1

Witness: Matthew M. DirksenMichigan Gas Utilities Corporation

Projected Test Year Calendar Sales in MCFCalendar Sales in MCF For the 12 Months Ending, December 31, 2014

Ln Rate Class Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total

Residential Rate1 Residential General 40,821 35,206 29,144 16,905 7,878 3,941 3,479 3,517 5,318 13,350 23,374 35,775 218,7072 Residential Heating 2,011,755 1,735,047 1,436,272 833,139 388,266 194,215 171,441 173,303 262,089 657,916 1,151,919 1,763,094 10,778,4563 Residential Lighting 30 30 42 25 25 30 30 36 39 50 36 31 4044 Total Residential 2,052,606 1,770,283 1,465,457 850,069 396,169 198,186 174,950 176,856 267,446 671,316 1,175,329 1,798,900 10,997,567

Multiple Family Rate5 Meter Class I 3,507 3,330 2,893 1,891 971 711 693 698 790 1,142 1,864 2,685 21,1756 Meter Class II 18,195 15,203 14,124 8,701 4,871 3,686 3,574 3,610 4,427 7,543 11,236 15,883 111,0537 Meter Class III 4,819 4,919 3,333 2,330 1,567 967 971 1,097 1,225 2,029 3,328 4,796 31,3808 Meter Class IV 7,974 6,667 5,351 3,459 2,175 1,179 1,009 874 1,167 3,099 5,034 7,701 45,6879 Total Multi-Family 34,495 30,119 25,700 16,381 9,584 6,543 6,246 6,278 7,609 13,813 21,462 31,065 209,295

C&I General Service Rate10 Small General Service 580,510 500,579 414,373 241,166 113,807 58,271 51,712 52,197 77,471 190,241 330,983 505,432 3,116,74211 Large General Service 55,125 46,244 41,038 26,031 14,088 8,881 8,575 7,962 10,719 18,681 26,654 41,927 305,92312 Commercial Lighting 97 97 135 79 79 97 97 114 126 162 115 98 1,297

13 Special Contracts 0 0 0 0 0 0 0 0 0 0 296 30 32614 Total C&I General Service 635,732 546,920 455,545 267,276 127,974 67,249 60,384 60,274 88,315 209,084 358,048 547,487 3,424,288

Transportation Service Rate15 Transportation Rate TR-1 251,753 225,446 177,321 152,399 106,954 89,303 82,705 92,350 99,027 152,847 175,161 215,898 1,821,16516 Additional Meters TR-1 0 0 0 0 0 0 0 0 0 0 0 0 0

17 Transportation Rate TR-2 432,392 384,748 360,291 306,020 283,668 288,933 311,289 273,261 254,221 291,233 324,765 372,559 3,883,38118 Additional Meters TR-2 0 0 0 0 0 0 0 0 0 0 0 0 0


21 Remote Meter Reading Charge 0 0 0 0 0 0 0 0 0 0 0 0 022 Administrative Charge 0 0 0 0 0 0 0 0 0 0 0 0 0

23 Transport Aggregated-Residential 1,251 1,086 636 563 241 96 74 69 156 362 657 915 6,10624 Transport Aggregated-Small C&I 175,373 169,440 136,229 97,784 74,606 45,845 43,213 51,076 45,057 63,043 345,987 143,474 1,391,12725 Transport Aggregated-Large C&I 3,754 6,486 5,500 2,464 1,632 136 57 32 117 737 2,328 4,522 27,764

26 Customer Choice-Residential 430,196 373,753 311,670 182,120 85,498 43,083 38,312 39,015 59,440 150,321 265,150 408,856 2,387,41427 Customer Choice-Small C&I 378,343 327,070 271,424 158,370 74,925 38,464 34,225 34,638 51,552 126,947 221,476 339,143 2,056,57728 Customer Choice-Large C&I 0 0 0 0 0 0 0 0 0 0 0 0 0

29 Customer Choice-Multi-Fam 01 474 425 274 185 86 82 67 54 143 257 344 593 2,98430 Customer Choice-Multi-Fam 02 1,408 1,336 1,127 709 500 384 296 298 479 925 983 1,949 10,39331 Customer Choice-Multi-Fam 03 0 0 0 0 0 0 0 0 0 0 0 0 032 Customer Choice-Multi-Fam 04 8,025 6,887 5,976 3,807 2,164 1,411 1,426 1,447 1,559 2,775 4,818 6,351 46,64533 Total Transportation 2,034,413 1,838,933 1,574,708 1,246,921 931,977 775,260 771,128 800,316 808,564 1,099,084 1,664,969 1,827,890 15,374,163

34 Total Calendar Sales 4,757,246 4,186,255 3,521,410 2,380,647 1,465,703 1,047,238 1,012,708 1,043,723 1,171,935 1,993,297 3,219,808 4,205,341 30,005,312

35 Total Transportation @ Customer Meter 2,034,413 1,838,933 1,574,708 1,246,921 931,977 775,260 771,128 800,316 808,564 1,099,084 1,664,969 1,827,890 15,374,163

36 Total GCR Sales @ Customer Meter 2,722,833 2,347,322 1,946,703 1,133,726 533,727 271,978 241,580 243,407 363,371 894,213 1,554,839 2,377,451 14,631,149




Michigan Gas Utilities CorporationProjected Test Year Fixed Charge Count

For the 12 Months Ending, December 31, 2014


Residential Rate1 Residential General 3,189 3,180 3,116 3,172 3,236 3,168 3,130 3,126 3,095 3,095 3,090 3,105 37,7022 Residential Heating 122,600 122,483 122,420 122,238 122,046 121,986 121,893 121,766 121,663 121,528 121,397 121,246 1,463,2663 Residential Lighting 0 0 0 0 0 0 0 0 0 0 0 0 04 Total Residential 125,789 125,663 125,536 125,410 125,282 125,154 125,023 124,892 124,758 124,623 124,487 124,351 1,500,968

Multiple Family Rate5 Meter Class I 125 125 125 125 126 126 125 122 122 123 125 126 1,4956 Meter Class II 206 206 206 206 206 206 207 211 211 210 208 206 2,4897 Meter Class III 17 17 17 17 17 17 17 17 17 17 16 17 2038 Meter Class IV 11 11 11 11 11 11 11 10 10 10 11 11 1299 Total Multi-Family 359 359 359 359 360 360 360 360 360 360 360 360 4,316

C&I General Service Rate10 Small General Service 7,657 7,648 7,637 7,626 7,616 7,604 7,592 7,580 7,569 7,556 7,543 7,532 91,16011 Large General Service 17 17 17 17 17 17 17 16 16 16 16 16 19912 Commercial Lighting 0 0 0 0 0 0 0 0 0 0 0 0 0

13 Special Contracts 1 1 1 1 1 1 1 1 1 1 1 1 1214 Total C&I General Service 7,675 7,666 7,655 7,644 7,634 7,622 7,610 7,597 7,586 7,573 7,560 7,549 91,371

Transportation Service Rate15 Transportation Rate TR-1 112 112 112 112 112 112 112 112 112 112 112 112 1,34416 Additional Meters TR-1 0 0 0 0 0 0 0 0 0 0 0 0 0

17 Transportation Rate TR-2 39 39 39 39 39 39 39 39 39 39 39 39 46818 Additional Meters TR-2 0 0 0 0 0 0 0 0 0 0 0 0 0



23 Transport Aggregated-Residential 34 34 34 34 34 34 34 34 34 34 34 34 40824 Transport Aggregated-Small C&I 498 498 498 498 498 498 498 498 498 498 498 498 5,97625 Transport Aggregated-Large C&I 3 3 3 3 3 3 3 3 3 3 3 3 36

26 Customer Choice-Residential 26,377 26,544 26,713 26,883 27,052 27,224 27,398 27,572 27,747 27,921 28,099 28,275 327,80527 Customer Choice-Small C&I 4,990 4,994 5,002 5,009 5,013 5,020 5,025 5,032 5,036 5,041 5,048 5,054 60,26428 Customer Choice-Large C&I 0 0 0 0 0 0 0 0 0 0 0 0 0

29 Customer Choice-Multi-Fam 01 39 39 39 39 39 39 39 39 39 39 39 39 46830 Customer Choice-Multi-Fam 02 53 53 53 53 53 53 53 53 53 53 53 53 63631 Customer Choice-Multi-Fam 03 0 0 0 0 0 0 0 0 0 0 0 0 032 Customer Choice-Multi-Fam 04 11 11 11 11 11 11 11 11 11 11 11 11 13233 Total Transportation 32,163 32,334 32,511 32,688 32,861 33,040 33,219 33,400 33,579 33,758 33,943 34,125 397,621

34 Total Fixed Charge Count 165,986 166,022 166,061 166,101 166,137 166,176 166,212 166,249 166,283 166,314 166,350 166,385 1,994,276

35 Total Transportation 32,163 32,334 32,511 32,688 32,861 33,040 33,219 33,400 33,579 33,758 33,943 34,125 397,621

36 Total GCR Sales 133,823 133,688 133,550 133,413 133,276 133,136 132,993 132,849 132,704 132,556 132,407 132,260 1,596,655




Michigan Public Service CommissionMichigan Gas Utilities CorporationWeather Normalized StudyVirtual Weather Station Degree DaysComparison of moving average to actuals, calculating the average absolute different, and calculating the standard deviation

30 Year ABS 25 Year ABS 20 Year ABS 15 Year ABS 10 Year ABS 5 Year ABSLine Year Actual Normal Difference Normal Difference Normal Difference Normal Difference Normal Difference Normal Difference

(Col. 1) (Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13) (Col. 14)1 1993 6,695 6,543 152 6,521 174 6,484 211 6,482 213 6,352 343 6,357 338 2 1994 6,458 6,540 82 6,530 72 6,522 64 6,462 4 6,374 84 6,366 92 3 1995 6,649 6,539 110 6,519 130 6,511 138 6,435 214 6,368 281 6,285 364 4 1996 7,039 6,542 497 6,517 522 6,526 513 6,422 617 6,392 647 6,452 587 5 1997 6,821 6,552 269 6,541 280 6,534 287 6,457 364 6,481 340 6,661 160 6 1998 5,558 6,556 998 6,533 975 6,545 987 6,479 921 6,545 987 6,732 1,174 7 1999 6,007 6,526 519 6,519 512 6,473 466 6,418 411 6,436 429 6,505 498 8 2000 6,284 6,502 218 6,492 208 6,430 146 6,384 100 6,350 66 6,415 131 9 2001 5,773 6,488 715 6,489 716 6,402 629 6,375 602 6,397 624 6,342 569

10 2002 6,317 6,466 149 6,445 128 6,365 48 6,350 33 6,375 58 6,089 228 11 2003 6,654 6,443 211 6,433 221 6,356 298 6,359 295 6,360 294 5,988 666 12 2004 6,156 6,467 311 6,419 263 6,365 209 6,359 203 6,356 200 6,207 51 13 2005 6,243 6,449 206 6,392 149 6,347 104 6,312 69 6,326 83 6,237 6 14 2006 5,691 6,446 755 6,367 676 6,339 648 6,341 650 6,285 594 6,229 538 15 2007 6,062 6,406 344 6,334 272 6,315 253 6,321 259 6,150 88 6,212 150 16 2008 6,553 6,388 165 6,317 236 6,310 243 6,294 259 6,075 478 6,161 392 17 2009 6,415 6,373 42 6,320 95 6,305 110 6,284 131 6,174 241 6,141 274 18 2010 5,910 6,358 448 6,316 406 6,282 372 6,281 371 6,215 305 6,193 283 19 2011 6,185 6,323 413 6,295 385 6,295 385 6,177 267 6,222 312 6,236 326 20 2012 5,370 6,355 170 6,337 152 6,336 151 6,210 25 6,265 80 6,283 98

21 Average of Absolute Difference 339 329 313 300 327 34622 Order (lower # the better) 5 4 2 1 3 6

23 Standard Deviation 253 241 237 241 245 27424 Order (lower # the better) 5 2 1 3 4 6

Notes:The normals for each year have a one year lag. For instance, 2012 normals will run through 2011.




Michigan Public Service CommissionMichigan Gas Utilities CorporationWeather Normalized StudyVirtual Weather Station Degree DaysCalculating the square error, mean square error and root mean square error

30 Year Square 25 Year Square 20 Year Square 15 Year Square 10 Year Square 5 Year SquareLine Year Actual Normal Error Normal Error Normal Error Normal Error Normal Error Normal Error

(Col. 1) (Col. 2) (Col. 3) (Col. 4) (Col. 5) (Col. 6) (Col. 7) (Col. 8) (Col. 9) (Col. 10) (Col. 11) (Col. 12) (Col. 13) (Col. 14)1 1993 6,695 6,543 23,104 6,521 30,276 6,484 44,521 6,482 45,369 6,352 117,649 6,357 114,244 2 1994 6,458 6,540 6,724 6,530 5,184 6,522 4,096 6,462 16 6,374 7,056 6,366 8,464 3 1995 6,649 6,539 12,100 6,519 16,900 6,511 19,044 6,435 45,796 6,368 78,961 6,285 132,496 4 1996 7,039 6,542 247,009 6,517 272,484 6,526 263,169 6,422 380,689 6,392 418,609 6,452 344,569 5 1997 6,821 6,552 72,361 6,541 78,400 6,534 82,369 6,457 132,496 6,481 115,600 6,661 25,600 6 1998 5,558 6,556 996,004 6,533 950,625 6,545 974,169 6,479 848,241 6,545 974,169 6,732 1,378,276 7 1999 6,007 6,526 269,361 6,519 262,144 6,473 217,156 6,418 168,921 6,436 184,041 6,505 248,004 8 2000 6,284 6,502 47,524 6,492 43,264 6,430 21,316 6,384 10,000 6,350 4,356 6,415 17,161 9 2001 5,773 6,488 511,225 6,489 512,656 6,402 395,641 6,375 362,404 6,397 389,376 6,342 323,761

10 2002 6,317 6,466 22,201 6,445 16,384 6,365 2,304 6,350 1,089 6,375 3,364 6,089 51,984 11 2003 6,654 6,443 44,521 6,433 48,841 6,356 88,804 6,359 87,025 6,360 86,436 5,988 443,556 12 2004 6,156 6,467 96,721 6,419 69,169 6,365 43,681 6,359 41,209 6,356 40,000 6,207 2,601 13 2005 6,243 6,449 42,436 6,392 22,201 6,347 10,816 6,312 4,761 6,326 6,889 6,237 36 14 2006 5,691 6,446 570,025 6,367 456,976 6,339 419,904 6,341 422,500 6,285 352,836 6,229 289,444 15 2007 6,062 6,406 118,336 6,334 73,984 6,315 64,009 6,321 67,081 6,150 7,744 6,212 22,500 16 2008 6,553 6,388 27,225 6,317 55,696 6,310 59,049 6,294 67,081 6,075 228,484 6,161 153,664 17 2009 6,415 6,373 1,764 6,320 9,025 6,305 12,100 6,284 17,161 6,174 58,081 6,141 75,076 18 2010 5,910 6,358 200,704 6,316 164,836 6,282 138,384 6,281 137,641 6,215 93,025 6,193 80,089 19 2011 6,185 6,323 19,044 6,295 12,056 6,295 11,990 6,177 64 6,222 1,369 6,236 2,601 20 2012 5,370 6,355 970,409 6,337 934,192 6,336 933,890 6,210 705,600 6,265 800,500 6,283 834,121

21 Mean Square Error 214,940 201,765 190,321 177,257 198,427 227,412 22 Root Mean Square Error 463.62 449.18 436.26 421.02 445.45 476.88 23 Order (lower # the better) 5 4 2 1 3 6

Notes:The normals for each year have a one year lag. For instance, 2012 normals will run through 2011.

Case No. U-17273Exhibit No. A-5 (MMD-1)

Schedule: E4Page 1 of 2


Michigan Gas Utilities CorporationProjected Year Calendar Sales (15 year) in MCFFor the 12 Months Ending, December 31, 2014

Ln Rate Class Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total12 Residential Rate3 Residential General 40,158 33,932 28,707 16,177 8,136 3,990 3,477 3,503 5,021 13,187 22,000 34,930 213,2174 Residential Heating 1,979,093 1,672,275 1,414,738 797,265 400,950 196,642 171,333 172,633 247,450 649,908 1,084,198 1,721,439 10,507,9235 Residential Lighting 33 33 41 25 25 25 25 25 25 25 24 35 3426 Total Residential 2,019,284 1,706,240 1,443,486 813,467 409,111 200,657 174,834 176,161 252,496 663,120 1,106,221 1,756,404 10,721,482789 Multi-Family Rate

10 Meter Class I 3,276 3,126 2,725 1,791 984 754 715 719 797 1,103 1,718 2,499 20,20711 Meter Class II 16,998 14,270 13,303 8,242 4,941 3,907 3,686 3,717 4,468 7,292 10,354 14,777 105,95512 Meter Class III 4,502 4,617 3,139 2,207 1,590 1,025 1,001 1,129 1,237 1,961 3,067 4,462 29,93613 Meter Class IV 7,449 6,258 5,040 3,276 2,206 1,249 1,041 900 1,178 2,996 4,639 7,165 43,39514 Total Multi-Family 32,225 28,271 24,207 15,516 9,721 6,935 6,443 6,465 7,679 13,352 19,777 28,903 199,49415161718 C&I General Service Rate19 Small General Service 567,637 479,831 406,102 230,292 117,739 59,743 52,517 52,836 73,950 187,677 310,375 490,684 3,029,38320 Large General Service 55,125 46,244 41,038 26,031 14,088 8,881 8,575 7,963 10,719 18,681 26,654 41,927 305,92421 Commercial Lighting 105 105 130 81 81 82 82 82 81 81 77 111 1,0962223 Special Contracts 0 0 0 0 0 0 0 0 0 0 296 30 32624 Total C&I General Service 622,867 526,180 447,270 256,404 131,907 68,706 61,174 60,880 84,749 206,439 337,402 532,752 3,336,72925272829 Transportation Rate TR-1 251,753 225,446 177,321 152,399 106,954 89,303 82,705 92,350 99,027 152,847 175,161 215,898 1,821,16530 Additional Meters TR-1 03132 Transportation Rate TR-2 432,164 384,466 355,930 305,998 280,314 259,068 262,659 263,798 251,880 291,190 324,706 372,370 3,883,38133 Additional Meters TR-2 03435 Transportation Rate TR-3 351,444 342,256 304,259 342,500 301,703 267,523 259,462 308,075 296,815 309,638 323,300 333,632 3,740,60736 Additional Meters TR-3 03738 Remote Meter Reading Charge 0 0 0 0 0 0 0 0 0 0 0 0 039 Administrative Charge 0 0 0 0 0 0 0 0 0 0 0 0 04041 Transport Aggregated-Residential 1,251 1,086 636 563 241 96 74 69 156 362 657 915 6,10642 Transport Aggregated-Small C&I 175,373 169,440 136,229 97,784 74,606 45,845 43,213 51,076 45,057 63,043 345,987 143,474 1,391,12743 Transport Aggregated-Large C&I 3,754 6,486 5,500 2,464 1,632 136 57 32 117 737 2,328 4,522 27,764444546 Customer Choice-Residential 423,419 360,408 307,148 174,364 88,335 43,643 38,307 38,883 56,148 148,565 249,686 399,395 2,328,30147 Customer Choice-Multifamily 1 442 399 258 176 88 87 70 56 144 249 317 551 2,83648 Customer Choice-Multifamily II 1,315 1,254 1,061 672 507 407 306 307 483 894 906 1,813 9,92449 Customer Choice-Multifamily IV 7,498 6,465 5,628 3,605 2,194 1,496 1,472 1,490 1,573 2,682 4,440 5,909 44,45050 Customer Choice-Small C&I 369,954 313,513 266,006 151,228 77,515 39,436 34,757 35,062 49,210 125,236 207,686 329,247 1,998,85051 Customer Choice-Large C&I 0 0 0 0 0 0 0 0 0 0 0 0 052 Total Transportation 2,018,368 1,811,218 1,559,977 1,231,752 934,089 747,039 723,081 791,198 800,609 1,095,441 1,635,172 1,807,725 15,254,5095354 Total Calendar Sales 4,692,744 4,071,909 3,474,939 2,317,139 1,484,829 1,023,337 965,532 1,034,705 1,145,534 1,978,352 3,098,572 4,125,783 29,512,2145556 Total Transportation @ Customer Meter 2,018,368 1,811,218 1,559,977 1,231,752 934,089 747,039 723,081 791,198 800,609 1,095,441 1,635,172 1,807,725 15,254,5095758 Total GCR Sales @ Customer Meter 2,674,376 2,260,691 1,914,963 1,085,387 550,739 276,298 242,451 243,506 344,925 882,911 1,463,400 2,318,058 14,257,704

Case No. U-17273Exhibit No. A-5 (MMD-1)

Schedule: E4Page 2 of 2


Michigan Gas Utilities CorporationProjected Year Calendar Sales Difference between the 15 year and the 30 year Forecasts

For the 12 Months Ending, December 31, 2014Ln Rate Class Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total12 Residential Rate3 Residential General (663) (1,274) (437) (728) 257 49 (2) (14) (297) (163) (1,374) (845) (5,490)4 Residential Heating (32,662) (62,772) (21,533) (35,874) 12,685 2,427 (109) (670) (14,639) (8,008) (67,722) (41,655) (270,533)5 Residential Lighting 3 3 (1) 1 1 (5) (5) (10) (14) (25) (12) 4 (62)6 Total Residential (33,322) (64,043) (21,971) (36,602) 12,943 2,471 (116) (694) (14,950) (8,196) (69,108) (42,496) (276,085)789 Multi-Family Rate

10 Meter Class I (231) (204) (168) (100) 14 43 22 21 7 (38) (146) (187) (968)11 Meter Class II (1,197) (933) (821) (460) 70 221 113 108 41 (252) (882) (1,105) (5,098)12 Meter Class III (317) (302) (194) (123) 22 58 31 33 11 (68) (261) (334) (1,444)13 Meter Class IV (525) (409) (311) (183) 31 71 32 26 11 (103) (395) (536) (2,292)14 Total Multi-Family (2,270) (1,848) (1,493) (865) 137 392 197 187 70 (461) (1,685) (2,162) (9,801)15161718 C&I General Service Rate19 Small General Service (12,873) (20,748) (8,271) (10,874) 3,932 1,472 805 639 (3,521) (2,564) (20,608) (14,748) (87,359)20 Large General Service (0) 0 0 0 (0) (0) 0 0 0 0 0 0 021 Commercial Lighting 8 8 (5) 1 1 (15) (15) (33) (45) (81) (38) 12 (201)2223 Special Contracts 0 0 0 0 0 0 0 0 0 0 0 0 024 Total C&I General Service (12,865) (20,740) (8,276) (10,872) 3,933 1,457 790 606 (3,566) (2,645) (20,646) (14,736) (87,560)2526 Transportation Service Rate27 Transportation Rate TR-1 0 0 0 0 0 0 0 0 0 0 0 0 028 Additional Meters TR-1 02930 Transportation Rate TR-2 0 0 0 0 0 0 0 0 0 0 0 0 031 Additional Meters TR-23233 Transportation Rate TR-3 0 0 0 0 0 0 0 0 0 0 0 0 034 Additional Meters TR-33536 Remote Meter Reading Charge 0 0 0 0 0 0 0 0 0 0 0 0 037 Administrative Charge 0 0 0 0 0 0 0 0 0 0 0 0 03839 Transport Aggregated-Residential 0 0 0 0 0 0 0 0 0 0 0 0 040 Transport Aggregated-Small C&I 0 0 0 0 0 0 0 0 0 0 0 0 041 Transport Aggregated-Large C&I 0 0 0 0 0 0 0 0 0 0 0 0 0424344 Customer Choice-Residential (6,777) (13,345) (4,522) (7,756) 2,837 560 (5) (132) (3,292) (1,756) (15,464) (9,461) (59,114)45 Customer Choice-Multifamily 1 (31) (26) (16) (10) 1 5 2 2 1 (9) (27) (41) (149)46 Customer Choice-Multifamily II (93) (82) (66) (38) 7 23 9 9 4 (31) (77) (136) (469)47 Customer Choice-Multifamily IV (527) (423) (348) (202) 31 84 45 44 14 (93) (379) (442) (2,195)48 Customer Choice-Small C&I (8,389) (13,557) (5,418) (7,142) 2,590 972 532 424 (2,342) (1,711) (13,790) (9,896) (57,727)49 Customer Choice-Large C&I 0 0 0 0 0 0 0 0 0 0 0 0 050 Total Transportation (15,817) (27,433) (10,369) (15,147) 5,466 1,644 584 346 (5,614) (3,600) (29,737) (19,976) (119,653)5152 Total Calendar Sales (64,274) (114,064) (42,109) (63,486) 22,479 5,964 1,455 445 (24,060) (14,902) (121,176) (79,370) (493,099)5354 Total Transportation @ Customer Meter (15,817) (27,433) (10,369) (15,147) 5,466 1,644 584 346 (5,614) (3,600) (29,737) (19,976) (119,653)5556 Total GCR Sales @ Customer Meter (48,457) (86,631) (31,740) (48,339) 17,013 4,320 871 99 (18,446) (11,302) (91,439) (59,394) (373,446)


Schedule E5Page: 1 of 1


Michigan Public Service CommissionMichigan Gas Utilities CorporationChange in Revenues from 30 to 15 year forecastCompare MGUC Distribution Volumetric RatesIn dollars

30 Year Average Weather Forecasted Distribution Volumetric ChargesLine Rate Class Tariff Rate per MCF Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Yearly Total

1 Residential GCR $1.5987 $3,281,453 $2,830,103 $2,342,759 $1,358,965 $633,315 $316,792 $279,645 $282,682 $427,504 $1,073,153 $1,878,941 $2,875,852 $17,581,1642 Multiple Family GCR I II $1.1929 $25,889 $22,108 $20,299 $12,635 $6,969 $5,246 $5,090 $5,138 $6,223 $10,360 $15,627 $22,150 $157,7353 Multiple Family GCR III IV $1.0629 $13,597 $12,314 $9,229 $6,153 $3,978 $2,280 $2,104 $2,094 $2,542 $5,451 $8,888 $13,283 $81,9144 Small General Services GCR $1.1876 $689,414 $594,488 $492,109 $286,409 $135,157 $69,203 $61,413 $61,989 $92,005 $225,930 $393,075 $600,251 $3,701,4435 Residential GCC $1.5987 $687,755 $597,519 $498,267 $291,155 $136,686 $68,877 $61,249 $62,373 $95,027 $240,318 $423,895 $653,638 $3,816,7596 Small General Services GCC $1.1876 $449,320 $388,428 $322,343 $188,080 $88,981 $45,680 $40,646 $41,136 $61,223 $150,762 $263,025 $402,766 $2,442,3917 Multiple Family GCC I II $1.1929 $2,244 $2,100 $1,671 $1,067 $700 $556 $434 $420 $741 $1,410 $1,583 $3,031 $15,9578 Multiple Family GCC III IV $1.0629 $8,530 $7,321 $6,352 $4,046 $2,300 $1,500 $1,516 $1,538 $1,657 $2,949 $5,121 $6,750 $49,579

9Total 30 Year Average Weather Forecasted Distribution Volumetric Charges $5,158,201 $4,454,380 $3,693,029 $2,148,510 $1,008,085 $510,133 $452,097 $457,370 $686,921 $1,710,334 $2,990,155 $4,577,722 $27,846,942

10 15 Year Average Weather Forecasted Distribution Volumetric Charges11 Rate Class Tariff Rate per MCF Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Yearly Total12 Residential GCR $1.5987 $3,228,177 $2,727,713 $2,307,636 $1,300,450 $654,006 $320,750 $279,467 $281,589 $403,625 $1,060,090 $1,768,477 $2,807,907 $17,139,88713 Multiple Family GCR I II $1.1929 $24,185 $20,752 $19,120 $11,968 $7,068 $5,560 $5,251 $5,292 $6,280 $10,014 $14,400 $20,608 $150,49914 Multiple Family GCR III IV $1.0629 $12,702 $11,559 $8,693 $5,828 $4,035 $2,417 $2,170 $2,157 $2,566 $5,269 $8,190 $12,358 $77,94415 Small General Services GCR $1.1876 $674,126 $569,847 $482,287 $273,495 $139,827 $70,951 $62,369 $62,748 $87,823 $222,885 $368,601 $582,736 $3,597,69516 Residential GCC $1.5987 $676,920 $576,184 $491,038 $278,756 $141,221 $69,772 $61,242 $62,162 $89,763 $237,511 $399,173 $638,513 $3,722,25417 Small General Services GCC $1.1876 $439,357 $372,328 $315,909 $179,598 $92,057 $46,834 $41,277 $41,640 $58,442 $148,730 $246,648 $391,014 $2,373,83418 Multiple Family GCC I II $1.1929 $2,096 $1,971 $1,574 $1,011 $710 $589 $448 $433 $748 $1,363 $1,458 $2,820 $15,22019 Multiple Family GCC III IV $1.0629 $7,969 $6,871 $5,982 $3,832 $2,332 $1,590 $1,564 $1,584 $1,672 $2,850 $4,719 $6,280 $47,246

20Total 15 Year Average Weather Forecasted Distribution Volumetric Charges $5,065,532 $4,287,226 $3,632,239 $2,054,937 $1,041,256 $518,462 $453,788 $457,605 $650,919 $1,688,712 $2,811,666 $4,462,237 $27,124,579

21 Difference in Charges (15 Year Forecasted Distribution Volumetric Charges - 30 Year Forecasted Distribution Volumetric Charges)22 Rate Class Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Yearly Total23 Residential GCR ($53,276) ($102,390) ($35,123) ($58,515) $20,691 $3,958 ($178) ($1,093) ($23,879) ($13,063) ($110,464) ($67,945) ($441,277)24 Multiple Family GCR I II ($1,704) ($1,356) ($1,179) ($667) $99 $314 $161 $154 $57 ($346) ($1,227) ($1,542) ($7,236)25 Multiple Family GCR III IV ($895) ($755) ($536) ($325) $57 $137 $66 $63 $24 ($182) ($698) ($925) ($3,970)26 Small General Services GCR ($15,288) ($24,640) ($9,823) ($12,914) $4,670 $1,748 $956 $759 ($4,182) ($3,045) ($24,474) ($17,515) ($103,748)27 Residential GCC ($10,835) ($21,335) ($7,229) ($12,399) $4,535 $895 ($7) ($211) ($5,264) ($2,807) ($24,722) ($15,125) ($94,505)28 Small General Services GCC ($9,963) ($16,100) ($6,434) ($8,482) $3,076 $1,154 $631 $504 ($2,781) ($2,032) ($16,377) ($11,752) ($68,557)29 Multiple Family GCC I II ($148) ($129) ($97) ($56) $10 $33 $14 $13 $7 ($47) ($124) ($211) ($737)30 Multiple Family GCC III IV ($561) ($450) ($369) ($214) $33 $90 $48 $46 $15 ($99) ($403) ($470) ($2,333)

31Total Difference in Charges 15 Year vs. 30 Year Forecasted Distribution Volumetric Charges ($92,669) ($167,155) ($60,790) ($93,573) $33,170 $8,329 $1,691 $235 ($36,003) ($21,622) ($178,489) ($115,485) ($722,363)

32 Percent Difference33 Rate Class Jan-14 Feb-14 Mar-14 Apr-14 May-14 Jun-14 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Yearly Total34 Residential GCR -1.62% -3.62% -1.50% -4.31% 3.27% 1.25% -0.06% -0.39% -5.59% -1.22% -5.88% -2.36% -2.51%35 Multiple Family GCR I II -6.58% -6.13% -5.81% -5.28% 1.42% 5.99% 3.16% 3.00% 0.92% -3.34% -7.85% -6.96% -4.59%36 Multiple Family GCR III IV -6.58% -6.13% -5.81% -5.28% 1.43% 6.01% 3.14% 3.01% 0.94% -3.34% -7.85% -6.96% -4.85%37 Small General Services GCR -2.22% -4.14% -2.00% -4.51% 3.45% 2.53% 1.56% 1.22% -4.54% -1.35% -6.23% -2.92% -2.80%38 Residential GCC -1.58% -3.57% -1.45% -4.26% 3.32% 1.30% -0.01% -0.34% -5.54% -1.17% -5.83% -2.31% -2.48%39 Small General Services GCC -2.22% -4.14% -2.00% -4.51% 3.46% 2.53% 1.55% 1.23% -4.54% -1.35% -6.23% -2.92% -2.81%40 Multiple Family GCC I II -6.58% -6.14% -5.81% -5.29% 1.43% 5.97% 3.19% 2.98% 0.92% -3.37% -7.86% -6.96% -4.62%41 Multiple Family GCC III IV -6.57% -6.14% -5.82% -5.30% 1.42% 5.97% 3.18% 3.01% 0.92% -3.36% -7.86% -6.96% -4.71%42 Total Percent Difference -1.80% -3.75% -1.65% -4.36% 3.29% 1.63% 0.37% 0.05% -5.24% -1.26% -5.97% -2.52% -2.59%


Schedule: E1.1Page: 1 of 1

Witness: Matthew M. DirksenMichigan Gas Utilities Corporation

Historical Year Calendar Sales in MCFCalendar Sales in MCF For the 12 Months Ended, December 31, 2012


Residential Rate1 Residential General 38,250 31,464 15,386 14,095 7,829 4,053 4,213 4,455 4,314 12,223 21,875 30,201 188,3582 Residential Heating 1,868,538 1,500,535 807,550 698,230 373,495 191,419 174,978 184,132 210,868 641,308 1,166,820 1,403,154 9,221,0253 Residential Lighting 24 27 19 37 23 32 34 32 31 42 29 19 3444 Total Residential 1,906,812 1,532,025 822,954 712,362 381,347 195,504 179,225 188,618 215,213 653,573 1,188,723 1,433,373 9,409,728

Multiple Family Rate5 Meter Class I 2,567 2,087 1,150 1,342 805 555 469 490 551 1,354 1,813 1,885 15,0676 Meter Class II 14,379 11,597 6,511 8,121 4,482 3,107 2,389 2,358 3,094 8,724 10,442 10,887 86,0907 Meter Class III 4,168 3,141 1,377 1,423 894 553 381 495 477 2,211 2,479 2,907 20,5068 Meter Class IV 6,706 4,993 2,889 3,139 1,931 881 538 634 766 3,830 4,952 5,560 36,8199 Total Multi-Family 27,820 21,818 11,926 14,024 8,111 5,096 3,777 3,977 4,889 16,119 19,686 21,239 158,482

C&I General Service Rate10 Small General Service 440,466 380,430 180,498 163,861 74,996 51,072 49,209 51,482 57,749 152,807 283,155 335,325 2,221,05011 Large General Service 44,923 123,409 7,450 36,566 1,172 9,234 2,405 4,015 5,115 13,716 19,189 29,052 296,24512 Commercial Lighting 74 85 59 116 72 103 107 102 99 133 93 59 1,098

13 Special Contracts 0 0 0 0 0 0 0 0 0 0 255 0 25514 Total C&I General Service 485,463 503,923 188,007 200,543 76,239 60,409 51,721 55,599 62,962 166,655 302,692 364,435 2,518,647

Transportation Service Rate15 Transportation Rate TR-1 232,632 224,370 193,777 159,868 134,461 101,402 93,062 80,137 98,172 126,759 165,476 179,215 1,789,33116 Additional Meters TR-1 0 0 0 0 0 0 0 0 0 0 0 0 0




23 Transport Aggregated-Residential 939 1,296 643 528 395 123 36 69 102 242 772 1,092 6,23724 Transport Aggregated-Small C&I 128,563 133,984 89,876 128,084 26,157 50,784 19,323 21,305 27,996 41,173 70,094 132,271 869,61025 Transport Aggregated-Large C&I 5,714 2,885 6,007 6,588 123 1,511 -571 12 -12 180 667 3,064 26,168

26 Customer Choice-Residential 370,123 304,291 159,713 149,728 82,753 39,597 36,043 40,188 45,672 148,776 260,583 340,353 1,977,82127 Customer Choice-Small C&I 402,274 357,774 192,073 167,681 88,800 68,442 57,408 69,765 68,322 200,536 309,058 310,232 2,292,36628 Customer Choice-Large C&I 0 0 0 0 0 0 0 0 0 0 0 0 0

29 Customer Choice-Multi-Fam 01 337 231 141 204 85 -159 17 21 16 73 179 347 1,49130 Customer Choice-Multi-Fam 02 864 839 428 650 278 -323 104 137 71 262 344 566 4,22031 Customer Choice-Multi-Fam 03 0 0 568 965 475 0 0 0 0 0 0 0 2,00732 Customer Choice-Multi-Fam 04 3,099 1,984 691 1,276 455 -28 8 8 8 29 22 58 7,60933 Total Transportation 1,879,633 1,720,099 1,228,690 1,205,979 923,116 808,619 779,232 779,813 817,576 1,187,191 1,456,375 1,601,755 14,388,076

34 Total Calendar Sales 4,299,728 3,777,866 2,251,577 2,132,908 1,388,814 1,069,627 1,013,954 1,028,006 1,100,639 2,023,538 2,967,476 3,420,803 26,474,933

35 Total Transportation @ Customer Meter 1,879,633 1,720,099 1,228,690 1,205,979 923,116 808,619 779,232 779,813 817,576 1,187,191 1,456,375 1,601,755 14,388,078

36 Total GCR Sales @ Customer Meter 2,420,094 2,057,767 1,022,887 926,929 465,697 261,008 234,722 248,194 283,064 836,347 1,511,101 1,819,048 12,086,857




Michigan Gas Utilities CorporationHistorical Year Fixed Charge Count

For the 12 Months Ended, December 31, 2012


Residential Rate1 Residential General 3,238 3,200 3,212 3,184 3,175 3,194 3,196 3,074 3,105 3,142 3,162 3,085 37,9672 Residential Heating 127,875 125,711 126,289 125,704 125,062 125,592 125,170 122,939 123,503 124,083 124,509 124,130 1,500,5673 Residential Lighting 0 0 0 0 0 0 0 0 0 0 0 0 04 Total Residential 131,113 128,911 129,501 128,888 128,237 128,786 128,366 126,013 126,608 127,225 127,671 127,215 1,538,534

Multiple Family Rate5 Meter Class I 122 121 121 120 123 121 121 117 119 120 119 117 1,4416 Meter Class II 206 203 204 198 199 199 199 198 199 197 195 196 2,3937 Meter Class III 17 17 13 13 13 13 13 13 13 15 15 15 1708 Meter Class IV 12 11 11 11 11 11 11 11 11 11 11 11 1339 Total Multi-Family 357 352 349 342 346 344 344 339 342 343 340 339 4,137

C&I General Service Rate10 Small General Service 8,396 8,248 8,254 8,102 7,969 7,942 7,861 7,644 7,674 7,733 8,000 8,132 95,95511 Large General Service 25 26 67 52 30 21 20 19 19 20 18 20 33712 Commercial Lighting 0 0 0 0 0 0 0 0 0 0 0 0 0

13 Special Contracts 1 1 1 1 1 1 1 1 1 1 1 1 1214 Total C&I General Service 8,422 8,275 8,322 8,155 8,000 7,964 7,882 7,664 7,694 7,754 8,019 8,153 96,304

Transportation Service Rate15 Transportation Rate TR-1 108 109 111 111 112 113 113 112 112 113 113 111 1,33816 Additional Meters TR-1 0 0 0 0 0 0 0 0 0 0 0 0 0




23 Transport Aggregated-Residential 35 40 35 35 35 34 34 34 34 34 34 34 41824 Transport Aggregated-Small C&I 456 460 467 468 469 495 489 495 497 496 497 497 5,78625 Transport Aggregated-Large C&I 3 2 3 3 3 3 3 3 3 3 3 3 35

26 Customer Choice-Residential 22,672 22,673 22,991 23,373 23,399 23,566 23,602 23,386 23,890 23,919 23,948 25,942 283,36127 Customer Choice-Small C&I 4,846 4,831 4,866 4,894 4,940 4,957 4,939 4,881 4,909 4,918 4,923 4,878 58,78228 Customer Choice-Large C&I 0 0 0 0 0 0 0 0 0 0 0 0 0

29 Customer Choice-Multi-Fam 01 11 11 11 13 13 12 7 7 7 7 14 24 13730 Customer Choice-Multi-Fam 02 15 15 16 17 16 11 9 9 9 9 9 11 14631 Customer Choice-Multi-Fam 03 0 0 4 4 4 0 0 0 0 0 0 0 1232 Customer Choice-Multi-Fam 04 3 3 2 2 2 0 0 0 0 0 487 -487 1233 Total Transportation 28,193 28,188 28,549 28,963 29,037 29,235 29,241 28,973 29,507 29,545 30,074 31,054 350,559

34 Total Fixed Charge Count 168,085 165,726 166,721 166,348 165,620 166,329 165,833 162,989 164,151 164,867 166,104 166,761 1,989,534

35 Total Transportation 28,193 28,188 28,549 28,963 29,037 29,235 29,241 28,973 29,507 29,545 30,074 31,054 350,559

36 Total GCR Sales 139,892 137,538 138,172 137,385 136,583 137,094 136,592 134,016 134,644 135,322 136,030 135,707 1,638,975

STATE OF MICHIGAN



DIRECT TESTIMONY AND EXHIBIT OF

CHRISTINE M. PHILLIPS, CPA

FOR


June 7, 2013

- 1 -

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

CHRISTINE M. PHILLIPS, CPA PART I


A. My name is Christine M. Phillips. My business address is Integrys Business Support 2

(“IBS”), 130 East Randolph Drive, Chicago, Illinois 60601. I am Manager - Benefits 3

Accounting in the Benefits Accounting Department of Integrys Energy Group, Inc. 4

(“Integrys”). Both IBS and Michigan Gas Utilities Corporation (“MGUC”) are wholly-5

owned subsidiaries of Integrys. 6

7



10


A. I have a Bachelor of Science Degree from Illinois Wesleyan University with a major 12

in Accounting. I am registered in the State of Illinois as a Certified Public Accountant 13

(“CPA”) and have been employed by IBS or its predecessors since May of 1990. In 14

my current position in the Benefits Accounting Department, my primary duties 15

include the accounting for the costs of the employee benefit plans, coordinating the 16

forecasting done by the actuaries, and ensuring accounting and legal compliance of 17

the employee benefit plans and trusts for Integrys and its subsidiaries, including 18

- 2 -

MGUC. 1

2


A. Yes, I have. I have testified before the Illinois Commerce Commission on behalf of 4

The Peoples Gas Light and Coke Company, and North Shore Gas Company in 5

Docket Nos. 09-0240/0241, 11-0280/0281 and 12-0511/0512. I have submitted 6

testimony before the Michigan Public Service Commission on behalf of MGUC in 7

Case U-15990, and on behalf of Upper Peninsula Power Company in Case Nos. U-8

15988, U-16166 and U-16167. I have also submitted testimony before the Public 9

Service Commission of Wisconsin in Docket Nos. 6690-UR-119, 6690-UR-120 and 10

6690-UR-121.11

- 3 -

CHRISTINE M. PHILLIPS, CPA DIRECT TESTIMONY

PART II


A. The purpose of my pre-filed direct testimony is to explain the methodologies used to 2

determine MGUC’s forecast of 2014 employee benefit costs. 3

4


A. Yes, I am. I am sponsoring Exhibit A-3 (CMP-1), Schedules C34 and C35. 6

7

Q. Were Schedules C34 and C35 of Exhibit A-3 (CMP-1) prepared by you or under 8

your direction and supervision? 9


11

Q. Please describe Exhibit A-3 (CMP-1), Schedule C34. 12

A. Exhibit A-3 (CMP-1), Schedule C34 is a summary, by sub-account, of employee 13

benefit costs for MGUC employees for the 2012 historic year, and the 2014 projected 14

year, inclusive of MGUC’s allocation of employee benefit costs from IBS. 15

16

Q. Please describe Exhibit A-3 (CMP-1), Schedule C35. 17

A. Exhibit A-3 (CMP-1), Schedule C35 is a summary, by sub-account, of IBS employee 18

benefit costs for the 2012 historic year, and the 2014 projected year. This exhibit 19

also calculates MGUC’s allocation of employee benefit costs from IBS. 20

21

Q. What is the current forecast of employee benefit costs for MGUC for 2014? 22

A. The current forecast of employee benefit costs for MGUC, on a corporate basis, for 23

the 2014 projected year is $4,415,106 inclusive of MGUC’s allocation of employee 24

- 4 -

benefit costs from IBS. This compares to $4,778,672 for the 2012 historic year, on a 1

corporate basis. This is a decrease of $363,566 over a two-year period, or 7.6%. 2

This 7.6% decrease over two years corresponds to a decrease of 3.73% per year. 3

4

Forecasting Methodologies 5 Q. How was the forecast of employee benefit costs for MGUC for 2014 6

developed? 7

A. As shown on Exhibit A-3 (CMP-1), Schedule C34, MGUC divided the forecast of 8

employee benefit costs into three categories. These categories were: 9

1. Forecasted 2014 costs that were determined by MGUC estimates, 10 11 2. Forecasted 2014 costs that were determined by inflating 2012 actual 12

costs, and 13 14 3. Forecasted 2014 costs that were determined through actuarial analysis. 15

16

Employee Benefit Costs that were Estimated by MGUC 17 Q. Please describe the process used to determine the forecasted 2014 employee 18

benefit costs that were determined by MGUC estimates. 19

A. There are six. The total impact of these three items is a net increase of $543,943 20

from 2012 to 2014. 21

22

First, as shown on Exhibit A-3 (CMP-1), Schedule C34, line 1, regarding the costs 23

recorded in Account 926080 A&G Dental Benefits, MGUC estimates the 2014 costs 24

to be $117,955. The overall increase in 2014 costs as compared to 2012 costs is 25

$13,313. Projected dental costs were calculated by using a 5% annual inflation rate 26

for 2013 and a 4% annual inflation rate for 2014 based on preliminary renewal 27

results and trend information received from MGUC’s independent actuary, Towers 28

Watson (“Towers”). 29

30

- 5 -

Second, as shown on Exhibit A-3 (CMP-1), Schedule C34, line 2, regarding the costs 1

recorded in Account 926090 A&G Medical Benefits, MGUC estimates the 2014 costs 2

to be $1,420,500. The overall increase in 2014 costs as compared to 2012 costs is 3

$229,708. Projected medical costs for 2014 were calculated by using a 7.5% annual 4

inflation rate based on preliminary renewal results and trend information received 5

from MGUC’s actuary, Towers. 6

7

Third, as shown on Exhibit A-3 (CMP-1), Schedule C34, line 3, regarding the costs 8

recorded in Account 926190 Goal Sharing, MGUC estimates the 2014 costs to be 9

$0. 10

11

Fourth, as shown on Exhibit A-3 (CMP-1), Schedule C34, line 4, regarding the costs 12

recorded in Account 926255 Defined Contribution Plan Expense, MGUC estimates 13

the 2014 costs to be $290,086. The overall increase in 2014 as compared to 2012 14

costs is $272,803. The increase is a result of changes to the pension plan benefit 15

design for administrative employees made in 2007 and effective January 1, 2008. 16

Administrative employees hired after January 1, 2008 are not eligible for pension 17

benefits. Instead, they receive an annual contribution to the defined contribution 18

plan. Effective January 1, 2013, all administrative employees will receive this annual 19

contribution as the freeze for service credits on the defined benefit pension plan 20

commences. The projected costs for administrative employees were based on the 21

amount of the benefit if all administrative employees would have received this benefit 22

in 2011 and inflated with a general wage increase to 2014. Union employees of 23

Local 12295 of the United Steelworkers Union hired on or after January 16, 2010 and 24

union employees of Local 417 Utility Workers Union of America hired on or after 25

February 16, 2012 are not eligible for pension benefits. Instead, these union 26

employees receive an annual contribution to the defined contribution plan. The 27

- 6 -

projected costs for union employees were based on 12% of the 2014 union payroll 1

with a 5% contribution. 2

3

Fifth, as shown on Exhibit A-3 (CMP-1), Schedule C34, line 5, regarding the costs 4

recorded in Account 926510 Legacy Aquila Defined Contribution Expense, MGUC 5

estimates the 2014 costs to be $0. The overall decrease in 2014 costs as compared 6

to 2012 costs is $40,584. As of December 31, 2012, this legacy Aquila defined 7

contribution benefit ended for all of MGUC employees. 8

9

Lastly, as shown on Exhibit A-3 (CMP-1), Schedule C34, line 6, regarding the costs 10

recorded in Account 926300 IBS Billed Benefits, MGUC estimates the 2014 costs to 11

be $1,046,464. The overall increase in 2014 costs as compared to 2012 costs is 12

$440. The primary driver behind holding costs about the same for the 2014 test year 13

and 2012 is a result of changes to the pension plan benefit design for administrative 14

employees made in 2007 and effective January 1, 2008. Administrative employees 15

hired after January 1, 2008 are not eligible for pension benefits. Instead, they 16

receive an annual contribution to the defined contribution plan. Effective January 1, 17

2013, all administrative employees will receive this annual contribution as the freeze 18

for service credits on the defined benefit pension plan commences. 19

20

Q. How were IBS employee benefit cost projections calculated? 21

A. IBS employee benefits cost projections relied on the same assumptions, actuarial 22

analyses, and methodologies used for MGUC employee benefit costs, as described 23

in this testimony. 24

25

Detail regarding the IBS employee benefits costs is shown on Exhibit A-3 (CMP-1), 26

Schedule C35, line 34. 27

- 7 -

Employee Benefit Costs that were Determined by Inflating 2012 Actual Costs 1 Q. Please describe the process used to determine the forecasted 2014 employee 2

benefit costs that were determined by inflation. 3

A. As shown on Exhibit A-3 (CMP-1), Schedule C34, for the sub-accounts shown on 4

lines 10 through 24, MGUC inflated 2012 actual costs by the inflation factors 5

developed by MGUC witness Ms. Katherine A. De Cramer, CPA in her Exhibit A-7 6

(KAD-4). The overall decrease in costs forecasted by inflating 2012 costs to 2014 7

was $30,624, or 3.7%. This 3.7% decrease over two years corresponds to 1.83% 8

per year. 9

10

Employee Benefit Costs that were Determined by Actuarial Analysis 11 Q. Please describe the process used to determine the forecasted 2014 employee 12

benefit costs that were determined by actuarial analysis. 13

A. As shown on Exhibit A-3 (CMP-1), Schedule C34, for five sub-accounts, MGUC 14

relied on an actuarial analysis to determine forecasted 2014 employee benefit costs. 15

The specific methods and assumptions employed are described below. The overall 16

decrease in costs from 2012 to 2014 forecasted by actuarial analysis is $876,885, or 17

a decrease of 26.8%. This 26.8% decrease over two years corresponds to 14.44% 18

per year. 19

20

The 2014 employee benefit costs that were determined by actuarial analysis are 21

related to: 22

1. Pension, 23

2. Post Retirement Medical, 24

3. Pension Restoration, 25

4. Supplemental Pension, and 26

5. Post Retirement Life. 27

28

- 8 -

Employee Pension Expense 1 Q. Please describe the development of the pension expense shown on line 27 of 2

Exhibit A-3 (CMP-1), Schedule C34. 3

A. Pension expense is determined using actuarial analysis, which is performed in 4

accordance with Financial Accounting Standards Board (“FASB”) Accounting 5

Standards Codification (“ASC”) 715-30, Defined Benefit Plans – Pension (“ASC 715-6

30”, formerly Statement of Financial Accounting Standards (“SFAS”) No. 87). 7

MGUC follows Generally Accepted Accounting Principles (“GAAP”) for its financial 8

statements. Under the provisions of GAAP, ASC 715-30 describes the 9

methodologies and assumptions used to calculate and account for pension expense. 10

ASC 715-30 requires an annual determination of the pension expense for the year. 11

This expense is determined by the actuary each year based upon: 12

1. Employee census data, 13

2. Current plan provisions, 14

3. Plan asset performance, and 15

4. Certain other actuarial assumptions. 16

17

For the ASC 715-30 pension expense, MGUC’s actuary, Towers, performs the 18

calculations required by this accounting standard annually to determine MGUC’s 19

pension expense. MGUC’s external auditors, Deloitte & Touche (“D&T”), review the 20

actuarial assumptions used to ensure consistency with GAAP. 21

22

There are four components of the ASC 715-30 pension expense. They are: 23

1. Service cost, 24 25 2. Interest cost, 26

27 3. Expected earnings on plan assets, and 28

29 4. Amortization of gains and losses, prior service costs, and any transitional 30

amounts. 31

- 9 -

1

Service cost represents one-year’s pro-rata share of the expected benefits earned 2

during the year by current active employees. 3

4

Interest cost represents interest on the plan’s benefit obligation (its liabilities) due to 5

the passage of time. 6

7

There is also an assumption regarding the expected return on assets for the year, 8

which is measured against the actual returns for the period. This rate of return 9

assumption is intended to be a long-term assumption of the return on plan assets. 10

11

The final component represents the amortization of various plan experiences that 12

were not anticipated by actuarial assumptions. 13

14

In order to calculate the plan’s total benefit obligation and annual ASC 715-30 15

expense, the actuary uses a number of assumptions including: 16

1. Mortality tables, 17

2. Retirement rates from MGUC, 18

3. Anticipated salary increases, 19

4. Expected return on plan assets, 20

5. Interest crediting rate, and 21

6. Discount rate. 22

23

Integrys management, as well as MGUC’s external auditor, D&T, reviews these 24

assumptions for reasonableness. A rate of return on assets of 8.00%, and a 25

discount rate of 4.10%, were used to forecast the 2014 pension expense. 26

27

- 10 -

The actuary then calculates the annual ASC 715-30 pension expense for MGUC. 1

This amount was $1,207,783 in 2012, and is projected to be $596,016 for 2014. This 2

is a decrease of $611,767. 3

4

Also included in this expense for both 2012 and 2014 is $821,606 of amortization 5

expense authorized by the Commission’s January 9, 2007 Order in Case No. U-6

15138. 7

8

Q. What actions has MGUC taken to help control pension costs? 9

A. During 2007, MGUC made changes to the retirement benefits provided to nonunion 10

employees. The most significant change was a shift from the traditional “defined 11

benefit” pension plan to a “defined contribution” model integrated with the existing 12

401K plan. 13

14

Effective January 1, 2008, the defined benefit pension plan was closed to 15

administrative (non-union) new hires. Those administrative employees participating 16

in the defined benefit pension plan as of January 1, 2008 continued to accrue 17

pension benefits through December 31, 2012, and the pay rate used in the 18

calculation of pension benefits will be frozen after December 31, 2017. On and after 19

January 1, 2013, pension benefits will no longer accrue under the defined benefit 20

pension plan, and all administrative employees will only have an annual contribution 21

made to their 401K account. Employees hired on and after January 1, 2008 do not 22

participate in the defined benefit pension plan, and will only have an annual 23

contribution made to their 401K account. 24

25

Effective January 16, 2010 for union employees of Local 12295 of the United 26

Steelworkers Union and February 16, 2012 for union employees of Local 12295 of 27

- 11 -

the United Steelworkers Union, the defined benefit pension plan was closed to union 1

new hires. Instead, these union employees receive an annual contribution to the 2

defined contribution plan 3

4

In addition, MGUC has made contributions to fund the pension plan. MGUC funded 5

$7.1 million in 2012 and $3.6 million in 2013. MGUC expects to contribute an 6

additional $4.7 million to the pension plan in 2014. As a result of these contributions 7

to MGUC’s pension plan, there are higher plan assets. The higher plan assets result 8

in higher expected earnings, thus decreasing pension expense. 9

10

Q. Are other U.S. utilities funding their pension and Other Post Employment 11

Benefits (“OPEB”) plans similarly to MGUC? 12

A. Yes, they are. In fact, on May 19, 2009, Standards & Poor issued a report entitled 13

“Funding Shortfall of U.S. Utility Pension and Postretirement Benefits Adds to 14

Industry’s Cost Pressure Woes.” 15

16

Based on this report, it is clear that many U.S. utilities are funding their pension and 17

OPEB plans similarly to MGUC. Also, the report highlights the fact that most state 18

regulators authorize rate recovery of the associated costs. 19

20

Due to copyright restrictions, a copy of this report cannot be electronically filed with 21

this case. However, MGUC will provide a hardcopy of this report to Commission 22

Staff and to the parties in this proceeding upon request. 23

24

Post Retirement Medical 25 Q. Please describe the development of the post retirement medical expense 26

shown on line 28 of Exhibit A-3 (CMP-1), Schedule C34. 27

- 12 -

A. The expense for retirees is determined using actuarial analysis, which is performed 1

in accordance with ASC 715-60, Defined Benefit Plans - Other Postretirement (“ASC 2

715-60”, formerly “SFAS 106”). As stated above, MGUC follows GAAP for its 3

financial statements. Under the provisions of GAAP, ASC 715-60 describes the 4

methodologies and assumptions used to calculate and account for retiree health care 5

expense. 6

7

The actuary performs the calculations required by this accounting standard annually 8

to determine MGUC’s ASC 715-60 expense. D&T reviews the actuarial assumptions 9

used to ensure consistency with GAAP. 10

11

ASC 715-60 requires an annual determination of the retiree health care expense for 12

the year, also referred to as OPEB expense or Post Employment Benefits other than 13

Pension (“PBOP”). This expense is determined by the actuary each year based 14

upon: 15

1. Employee census data, 16

2. Current plan provisions, 17

3. Plan asset performance, and 18

4. Certain other actuarial assumptions. 19

20

There are four components of SFAS No. 106 expense: 21

1. Service cost, 22 23 2. Interest cost, 24 25 3. Expected earnings on plan assets, and 26 27 4. Amortization of gains and losses, prior service costs, and any transitional 28

amounts. 29 30

These are the same four components that are used in the calculation of pension 31

- 13 -

expense, although different assumptions are used for health care. 1

2

In order to calculate the plan’s total benefit obligation and annual ASC 715-60 3

expense, the actuary uses a number of assumptions including: 4

1. Health care inflation trend rates, 5

2. Mortality tables, 6

3. Retirement rates from MGUC, 7

4. Actual retiree health care claims experience specific to MGUC, 8

5. Expected return on plan assets, and 9

6. A discount rate. 10

11

Integrys management, as well as MGUC’s external auditor, D&T, reviews these 12

assumptions. A rate of return on assets of 8.00% and a discount rate of 3.60% was 13

used to forecast the 2014 administrative post retirement medical expense. A rate of 14

return on assets of 8.00% and a discount rate of 4.05% was used to forecast the 15

2014 non-administrative or union post retirement medical expense. 16

17

The actuary then calculates the annual ASC 715-60 expense component for each 18

year, which was $417,227 for the 2012 historic test year, and is projected to be 19

$184,744 for the 2014 projected test year. This is a decrease of $232,483. 20

21



15138. 24

25

Furthermore, included in this expense for 2012 is $31,000 of amortization expense 26

authorized by the Commission’s December 8, 1992 Order in Case No. U-10040. 27

- 14 -

This was fully amortized as of December 31, 2012. The projected 2014 test year 1

cost is $0. This is a decrease of $31,000. 2

3

Pension Restoration 4 Q. Please describe the development of the pension restoration plan expense 5


A. The pension restoration plan expense is calculated in accordance with ASC 715-30 7

accounting rules, identical in nature to the pension expense described above. A 8

discount rate of 3.20% was used to forecast the 2014 pension restoration plan 9

expense. This amount was $10,429 in 2012, and is projected to be $9,068 for the 10

2014 test year, which is a decrease of $1,361. 11

12

Also included is plan expense of the Deferred Income Plan. The Deferred Income 13

Plan expense was determined by using the Moody’s Corporate Bond Yield Average 14

A of 4.96% for 2012 and 4.42% was used to forecast the 2014 Deferred Income Plan 15

expense for the test year. This amount was $8,010 in 2012, and is projected to be 16

$6,745 for the 2014 test year, which is a decrease of $1,265. 17

18

Supplemental Pension 19 Q. Please describe the development of the supplemental pension plan expense 20


A. The supplemental pension plan expense is calculated in accordance with ASC 715-22

30 accounting rules, identical in nature to the pension expense described above. A 23

discount rate of 3.45% was used to forecast the 2014 supplemental pension plan 24

expense. This amount was $27,709 in 2012, and is projected to be $20,837 for the 25

2014 test year, which is a decrease of $6,872. 26

27


- 15 -


15138 2

3

Post Retirement Life 4 Q. Please describe the development of the post retirement life benefit plan 5

expense shown on line 31 of Exhibit A-3 (CMP-1), Schedule C34. 6

A. The post retirement life insurance expense is calculated in accordance with the 7

requirements of ASC 715-60, consistent with the post retirement medical expense 8

described above. A rate of return on assets of 8.00%, and a discount rate of 4.00%, 9

were used to forecast the 2014 post retirement life insurance expense. This amount 10

was $1,729 in 2012, and is projected to be $9,592 in 2014. This is an increase of 11

$7,863. 12

13

Q. Will MGUC provide updated actuarial analyses when available? 14

A. Yes, it will. Upon request, MGUC will provide an updated actuarial analysis to 15

Commission Staff and to the parties in this proceeding if one is completed during the 16

pendency of this proceeding. 17

18


A. Yes, it does. 20

Case No.: U-17273Exhibit No.: A-3 (CMP-1)


Witness: Christine M. Phillips, CPAMICHIGAN GAS UTILITY COMPANY

Summary of Employee Benefits Costs

Test Year Ended December 31, 2014

2012 2014Actual Forecast Increase Increase Forecast

Line No. Sub-Account Description $ $ $ % Method1 926080 A&G Dental Benefits 104,642$ 117,955$ 13,313$ 12.7% MGUC Estimate2 926090 A&G Medical Benefits 1,190,792$ 1,420,500$ 229,708$ 19.3% MGUC Estimate3 926190 Goal Sharing (68,263)$ -$ 68,263$ -100.0% MGUC Estimate4 926255 Defined Contribution Plan Exp 17,283$ 290,086$ 272,803$ 1578.4% MGUC Estimate5 926510 Legacy Aquila Defined Contribution Expense 40,584$ -$ (40,584)$ -100.0% MGUC Estimate6 926300 IBS Billed Benefits 1,046,024$ 1,046,464$ 440$ 0.0% Exhibit A-3 (CMP-1), Schedule C357 Subtotal - MGUC Estimate 2,331,062$ 2,875,005$ 543,943$ 23.3%89

10 926000 A&G-Employee Pension and Benefits 11$ 11$ -$ 0.0% Inflationary11 926007 Company Match 401K 266,543$ 276,498$ 9,955$ 3.7% Inflationary12 926020 Time Away From Work Residual Balance 1,459,836$ 1,514,361$ 54,525$ 3.7% Inflationary13 926025 Time Away From Work - Clearing (1,531,061)$ (1,588,247)$ (57,186)$ 3.7% Inflationary14 926026 IBS Billed Non Productilve Time - Residual Balance (12,322)$ (12,782)$ (460)$ 3.7% Inflationary15 926050 Human Resources Dept General 39,346$ 40,816$ 1,470$ 3.7% Inflationary16 926070 Christmas Gift Check Expense - Retirees 4,625$ 4,798$ 173$ 3.7% Inflationary17 926120 Joint Plant A&G & Non-Utility Loading (12,779)$ (13,256)$ (477)$ 3.7% Inflationary18 926135 Fully-Insured Long Term Disability Premium Exp 24,496$ 25,411$ 915$ 3.7% Inflationary19 926140 A&G ESOP Contribution Expense 199,697$ 207,156$ 7,459$ 3.7% Inflationary20 926170 A&G Capitalized Pensions and Benefits (1,275,033)$ (1,322,656)$ (47,623)$ 3.7% Inflationary21 926191 IBS Billed Incentive Residual (25,335)$ (26,281)$ (946)$ 3.7% Inflationary22 926200 Employee Benefits Tuition Reimbursement 2,019$ 2,094$ 75$ 3.7% Inflationary23 926250 Company Provided Life Insurance 24,051$ 24,949$ 898$ 3.7% Inflationary24 926330 Benefits-Wellness 16,019$ 16,617$ 598$ 3.7% Inflationary25 Subtotal - Inflationary Items (819,887)$ (850,511)$ (30,624)$ 3.7%2627 926060 A&G Pension Expense 2,029,389$ 1,417,622$ (611,767)$ -30.1% Actuarial Analysis28 926180 A&G Post Retirement Medical 1,177,885$ 914,402$ (263,483)$ -22.4% Actuarial Analysis29 926210 Pension Restoration 18,439$ 15,813$ (2,626)$ -14.2% Actuarial Analysis30 926220 Supp Pension Plan Exp 40,055$ 33,183$ (6,872)$ -17.2% Actuarial Analysis31 926305 Post Retirement Life 1,729$ 9,592$ 7,863$ 454.8% Actuarial Analysis32 Subtotal - Actuarial Analysis 3,267,497$ 2,390,612$ (876,885)$ -26.8%3334 TOTAL EMPLOYEE BENEFIT COSTS 4,778,672$ 4,415,106$ (363,566)$ -7.6%

Case No.: U-17273Exhibit No.: A-3 (CMP-1)


Witness: Christine M. Phillips, CPAMICHIGAN GAS UTILITY COMPANY

Summary of IBS Employee Benefits Costs

Test Year Ended December 31, 2014

2012 2014Actual Forecast Increase Increase Forecast

Line No. Sub-Account Description $ $ $ % Method1 926080 A&G Dental Benefits 860,857$ 993,773$ 132,916$ 15.4% MGUC Estimate2 926090 A&G Medical Benefits 9,807,572$ 11,981,525$ 2,173,953$ 22.2% MGUC Estimate3 926190 Goal Sharing (674,154)$ -$ 674,154$ -100.0% MGUC Estimate4 926255 Defined Contribution Plan Exp 726,335$ 8,502,000$ 7,775,665$ 1070.5% MGUC Estimate5 Subtotal - MGUC Estimate 10,720,610$ 21,477,298$ 10,756,688$ 100.3%678 926000 A&G-Employee Pensions and Bene 19,672$ 20,407$ 735$ 3.7% Inflationary9 926020 Time Away From Work Residual Balance 16,980,785$ 17,615,024$ 634,239$ 3.7% Inflationary10 926025 Time Away From Work - Clearing (17,399,248)$ (18,049,117)$ (649,869)$ 3.7% Inflationary11 926050 Human Resources Department General 1,057,518$ 1,097,017$ 39,499$ 3.7% Inflationary12 926070 Christmas Gift Check - Retirees 8,532$ 8,851$ 319$ 3.7% Inflationary13 926120 Joint Plant A&G & Non-Utility Loading (854,363)$ (886,274)$ (31,911)$ 3.7% Inflationary14 926135 Fully-Insured Long Term Disability Premium 299,394$ 310,576$ 11,182$ 3.7% Inflationary15 926140 A&G ESOP Contribution Expense 5,460,538$ 5,664,491$ 203,953$ 3.7% Inflationary16 926170 A&G Capitalized Pensions and Benefits (1,129,772)$ (1,171,969)$ (42,197)$ 3.7% Inflationary17 926200 Employee Benefits Tuition Reimbursement 294,869$ 305,882$ 11,013$ 3.7% Inflationary18 926250 Company Provided Life Insurance 282,194$ 292,734$ 10,540$ 3.7% Inflationary19 926260 Executive Deferred Compensation ESOP Match 19,818$ 20,558$ 740$ 3.7% Inflationary20 926330 Benefits-Wellness 165,291$ 171,465$ 6,174$ 3.7% Inflationary21 Subtotal - Inflationary Items 5,205,227$ 5,399,645$ 194,418$ 3.7%2223 926017 Post Retirement Welfare FAS 106 673,821$ 699,223$ 25,402$ 3.8% Actuarial Analysis24 906019 Supplemental Employee Retirement Plan 145,515$ 14,051$ (131,464)$ -90.3% Actuarial Analysis25 926060 A&G Pension Expense 9,747,974$ (1,607,017)$ (11,354,991)$ -116.5% Actuarial Analysis26 926180 A&G Post Retirement Medical 52,801$ 1,237,932$ 1,185,131$ 2244.5% Actuarial Analysis27 926210 Pension Restoration and Supp Pension Plan Exp 1,319,918$ 664,926$ (654,992)$ -49.6% Actuarial Analysis28 926220 Supplemental Employee Retirement Plan 1,487,727$ 1,222,114$ (265,613)$ -17.9% Actuarial Analysis29 926305 Post Retirement Life 2,026$ 2,179$ 153$ 7.6% Actuarial Analysis30 926315 Long Term Disability Benefit (19,842)$ (41,913)$ (22,071)$ 111.2% Actuarial Analysis31 926325 Short Term Disability Benefit 3,573$ -$ (3,573)$ -100.0% Actuarial Analysis32 Subtotal - Actuarial Analysis 13,413,513$ 2,191,495$ (11,222,018)$ -83.7%3334 TOTAL EMPLOYEE BENEFIT COSTS 29,339,350$ 29,068,438$ (270,912)$ -0.9%3536 Allocation Percentage from IBS to MGUC 3.6% 3.6%3738 Allocation Dollars from IBS to MGUC 1,046,024$ 1,046,464$ 440$ 0.0%

STATE OF MICHIGAN




NOREEN E. CLEARY

FOR


June 7, 2013

- 2 -

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

NOREEN E. CLEARY PART I

Q. Please state your name, address and position. 1

A. My name is Noreen E. Cleary. My business address is Integrys Business Support, 2

130 E. Randolph St, Chicago, IL 60601. I am the Assistant Vice President, Total 3

Compensation for Integrys Energy Group, Inc. (“Integrys”). Integrys is the parent 4

corporation of Michigan Gas Utilities Corporation (“MGUC”). 5

6

Q. Please describe your educational and business experience. 7

A. I received a bachelor’s of science degree in Medical Technology from Fitchburg 8

State College, now Fitchburg State University, in 1981. My professional experience 9

in Human Resources (“HR”) covers a period of more than 25 years with various 10

companies. My primary expertise and concentration in the HR area has been in 11

compensation and benefits design and administration. I hold designations as a 12

Compensation Management Specialist (C.M.S.) and a Certified Employee Benefit 13

Specialist (C.E.B.S.) from the International Foundation of Employee Benefits 14

Programs (I.F.E.B.P.) in partnership with The Wharton School of the University of 15

Pennsylvania. 16

17



- 3 -

NOREEN E. CLEARY DIRECT TESTIMONY

PART II


A. My pre-filed direct testimony will describe the Integrys 2013 Non-Executive Incentive 2

Plan as it applies directly to MGUC and indirectly to MGUC through Integrys 3

Business Support, LLC (“IBS”) (“MGU Non-Executive Incentive Plan”). Non-4

executive employees of MGUC, as well as those of IBS, participate in the MGUC 5

Non-Executive Incentive Plan utilizing specific measures and targets designed for 6

MGUC. IBS is a separate subsidiary of Integrys that provides services to MGUC in 7

the areas of Gas Supply, Engineering, Customer Relations, shared services and 8

corporate support. This plan remains the same as the 2012 plan and uses metrics 9

specifically focused on providing benefits to customers in the form of reduced cost of 10

service, greater efficiencies in operations, increased customer satisfaction and 11

improved reliability 12

13


A. Yes, I am. I am sponsoring Exhibit A-9 (NEC-1), which is the Integrys 2013 IBS & 15

Regulated Non-Executive Incentive Plan. 16

17

Q. Was this exhibit prepared by you or under your direction and supervision? 18

A. Yes, it was. 19

20

Q. Please describe MGUC’s compensation philosophy. 21

A. Like most customer-focused businesses, including public utilities, MGUC maintains 22

compensation programs that are market-based so it can attract and retain a qualified 23

and motivated work force. We compete for quality employees in a market that 24

includes regulated and non-regulated energy companies as well as non-energy 25

- 4 -

firms. Virtually all firms with which MGUC competes for quality employees offer Pay-1

at-Risk as a portion of total compensation. This Pay-at-Risk is an expected 2

component of a total compensation package in today’s talent market place. Potential 3

employees are anticipating the opportunity to participate in the Company’s success 4

through such Pay-at-Risk programs as MGUC’s Annual Incentive Plan. 5

6

MGUC’s goal is to pay our employees a total cash compensation package (base pay 7

plus target Pay-at-Risk) that is anchored to market median levels, as compared to 8

other energy industry companies and general industry companies, based on data as 9

provided by Towers Watson, an internationally recognized firm that specializes in 10

both compensation and benefits consulting services. Stated another way, the 11

combination of the base pay target plus annual Pay-at-Risk target brings the 12

employee to the 50th percentile median of comparable energy industry and general 13

industry companies. Our compensation programs are reviewed at least annually 14

against competitive data. This review includes both market data and business 15

objectives to ensure our compensation programs will attract and retain a quality 16

workforce to serve our customers. 17

18

Q. If the Commission does not allow recovery of Pay-at-Risk costs, why couldn’t 19

MGUC simply pay its employees exclusively through base pay? 20

A. There are two reasons why MGUC needs to use a compensation package that 21

includes Pay-at-Risk rather than pay employees exclusively through base pay. First, 22

offering only base pay plans without a Pay-at-Risk component would make it more 23

difficult for MGUC to attract the quality employees required to provide a level of 24

service that our customers demand. Quality employees demand this type of Pay-at-25

Risk compensation to recognize superior performance. Indeed, surveys performed 26

by Towers Watson have concluded that the majority of companies extend their Pay-27

- 5 -

at-Risk programs deep into their organizations (i.e., at least to entry level 1

professionals). Second, including annual Pay-at-Risk plans in its compensation 2

program enables MGUC to offer competitive compensation packages that incent 3

employees to improve service levels and reduce costs that impact the rates paid by 4

customers. The 2013 Pay-at-Risk plan design will focus employees on key goals 5

and objectives that benefit our customers, as its design measure criteria will 6

concentrate on cost containment and operational goals that are aligned with the 7

interests of customers rather than financial measures that might be more aligned 8

with the interests of shareholders. 9

10

Q. Does a utility’s ability to attract and retain sufficient, qualified and motivated 11

work force benefit customers? 12

A. Absolutely. Attracting and retaining a sufficient, qualified and motivated work force 13

directly benefits customers, because it ensures there are enough highly proficient 14

employees to perform needed customer work. In addition, customers benefit by 15

MGUC maintaining and improving the productivity and quality of work performed, 16

which reduces overall costs to customers. By retaining trained and experienced 17

employees through a market-competitive compensation program, MGUC is able to 18

avoid incurring the costs of hiring and training employees to replace workers who 19

otherwise would choose to leave the company if such a market-competitive program 20

were not in place. Experienced employees who are familiar with MGUC’s systems 21

and equipment are more efficient in their performance, further reducing the 22

company’s operating and maintenance expenses and capital expenditures. 23

24

Q. Please review the current make up of the MGUC Non-Executive Incentive Plan. 25

A. The MGUC Non-Executive Incentive Plan rewards non-union employees on an 26

annual basis for meeting pre-determined goals in a number of areas which we 27

- 6 -

believe are in our customers’ best interests. It uses four specific 2013 performance 1

measures to determine Pay-at-Risk payouts for MGUC employees. The four 2

performance measures are all focused on operational aspects of the business, 3

including cost management. There is no financial performance measure in the plan. 4

MGUC’s measures assess cost control via a non-fuel Operations and Maintenance 5

(“O&M”) expense-adjusted metric which is weighted at 50% of the total. In addition, 6

employee safety measurements, customer service and system reliability are 7

weighted at a combined 50% of the total. The following is a high-level review of the 8

plan design: 9

10

Operational Performance Measures

1) Cost Management Non-fuel O&M Expense-

Adjusted

2) Employee Safety-OSHA-Recordable

Incident Rates 3) Customer Satisfaction 4) Reliability

50% 15% 15% 20%

11

Q. What is the focus of these operational measures? 12

A. Our operational measures are focused on improving services delivered to customers 13

including cost control of expenses that impact their rates. They are designed to 14

motivate employees to maintain customer support at a high quality level and at 15

competitive rates. 16

17

Q. Can you provide more details as to the operational performance measures in 18

the MGUC Non-Executive Incentive Plan? 19

A. Yes. The following chart provides details on the four operational measures. 20

21

- 7 -

Operational Performance Measure Description Weighting

1. Cost Management

Non-fuel O&M Expense Adjusted

Assess cost management via non-fuel O&M expense-adjusted, to help maintain or reduce expenses that may be charged to customers in future rate cases. All employees in the Plan are tied to this measure.

50%

2. Employee Safety

– OSHA-Recordable Incident Rates

Based on reducing OSHA recordable injuries and illnesses. A comparison to targets measuring recordable injuries and illnesses. All employees are tied to this measure.

15%

3. Customer

Satisfaction

Based on improving customer satisfaction, a residential customer survey measures overall customer satisfaction in categories such as reliability, communications, corporate citizenship, price and value, billing and payment, customer and field service. Customer satisfaction surveys are conducted by an independent third party and compared against the satisfaction survey results of other regional benchmark energy suppliers. All employees are tied to this measure.

15%

4. Reliability

This metric is based on improving performance of defective meter shut-off valve corrections. The objective is to reduce the number of outstanding broken, buried, and built over meter shut-off valves. This measure applies to all MGUC employee Incentive Plan participants.

20%

1

Q. Who participates in the MGUC Non-Executive Incentive Plan? 2

A. Participants in the MGUC Non-Executive Incentive Plan include MGUC non-union 3

non-executive employees, as well as employees of IBS. Employees of IBS affect the 4

MGUC Non-Executive Incentive Plan based on the proportion that IBS costs are 5

allocated to MGUC, as discussed in the pre-filed direct testimony of Tracy L. Kupsh. 6

- 8 -

1

Q. How does the Cost Management Non-fuel O&M Expense-adjusted metric 2

benefit customers? 3

A. The Cost Management Non-fuel O&M Expense-adjusted metric benefits customers 4

by reducing the costs of service that must be recovered from customers in future rate 5

cases. This metric encourages employees to maintain or reduce operational costs in 6

order to keep O&M costs at or below the target level set for MGUC. The more O&M 7

costs are reduced, the higher the payout for which employees may be eligible. This 8

metric benefits customers, because all else being equal, lowering O&M expenses will 9

reduce the amount of costs to be recovered in future rate cases. 10

11

To the extent any operations and maintenance savings are permanent, the result will 12

be lower rates for MGUC customers for years to come. 13

14

Q. How does the Employee Safety metric benefit customers? 15

A. The Employee Safety metric benefits customers by reducing costs and inefficiencies 16

associated with on-the-job accidents. The focus on employee safety is part of a 17

larger effort to create a “Safety Culture” in which all aspects of safety, public safety, 18

customer safety, as well as employee safety, become a daily part of what we do. 19

The Pay-at-Risk compensation metric is designed to encourage the reduction in the 20

number of OSHA-recordable incidents by MGUC employees. OSHA-recordable 21

incidents or indeed, accidents of any kind, cause higher operating expenses, which 22

ultimately result in higher rates for customers. Moreover, safer employees are more 23

motivated and efficient than those who operate in a less safe environment. Thus, by 24

encouraging increased safety for employees, this metric leads to more efficiency and 25

lower costs, which are a direct benefit to customers. 26

27

- 9 -

Q. How does the Customer Satisfaction metric benefit customers? 1

A. The Customer Satisfaction metric benefits customers by encouraging MGUC 2

employees to improve the Company’s performance with respect to customer 3

communications, customer service, and field service. This metric is designed to 4

ensure that MGUC customers receive an ever-improving level of high-quality service 5

in all aspects of MGUC’s delivery of natural gas to their homes and businesses. 6

Customers of MGUC benefit from this metric because it ensures that they continue to 7

receive high-quality service from MGUC employees and encourages further 8

improvements in that service quality. 9

10

Q. How does the Reliability metric benefit customers? 11

A. The Reliability metric benefits customers by reducing the number of defective meter 12

valve shut-offs, thereby enabling quick and efficient response time to the need for 13

shut-offs, both emergency and non-emergency. Quick and efficient shut-off 14

response benefits customers of MGUC by increasing their level of safety. 15

16

Q. What changes have been made to the 2013 MGU Non-Executive Incentive Plan 17

as compared to the historic test year? 18

A. The MGUC Non-Executive Incentive Plan from the historic test year utilized a 19

reliability measure that focused on Pipeline Locates Improvements. In an effort to 20

further incent MGUC employees to improve efficiency and processes, the 2013 21

reliability measure focuses on Meter Valve Remediation. The other three measures 22

in the Plan for the historic test year have remained the same, although targets have 23

been adjusted annually. 24

25

Q. Do you anticipate any additional changes to the Plan for the projected test 26

year? 27

- 10 -

A. No. For the 2014 projected test year our focus will likely continue to be on the four 1

measures described above, although targets will be adjusted annually. 2

3

Q. Do you propose that MGUC recover in rates the costs of the MGUC Non-4

Executive Incentive Plan in their entirety? 5

A. Yes. 6

7

Q. On what basis do you propose that MGUC recover in rates the costs of the 8

MGUC Non-Executive Incentive Plan in their entirety? 9

A. As described above, the MGUC Non-Executive Incentive Plan contains measures 10

designed exclusively to provide benefits to customers by encouraging the 11

achievement of operational goals focused on maintaining or reducing costs and 12

improving reliability and service. The MGUC Non-Executive Incentive Plan aligns 13

non-executive employee performance with customer interests. 14

15

Q. Have other MGUC utility affiliates been granted recovery of Pay-at-Risk costs? 16

A. Yes, they have. In Docket Number G-007,011/GR-10-977, MGUC affiliate 17

Minnesota Energy Resources Corporation was granted 100% recovery of Non-18

Executive Pay-at-Risk costs, and 30% recovery of Executive Pay-at-Risk costs. 19

20

Q. Do you have any further comments on the recovery of the Pay-at-Risk 21

component of total cash compensation? 22

A. Yes, I do. MGUC’s total cash compensation costs are targeted to the energy 23

industry and the general industry market median rates. These are prudent 24

expenditures that allow MGUC to continue customer-expected service levels and to 25

maintain competitive rates. If MGUC went to a more fixed-expense basis for 26

compensation in the form of increased base salaries, it would put the Company at a 27

- 11 -

disadvantage in a market where Pay-at-Risk programs are prevalent, and negatively 1

impact our ability to attract and retain the quality workforce needed to deliver high 2

levels of customer service without any benefit to the customer. 3

4


A. Yes, it does. 6

1/1/13

INTEGRYS

2013 IBS & Regulated Non-Executive Incentive Plan

Update 12/3/12

Case No. U-17273 Witness: Noreen E. Cleary

Exhibit A-10 (NEC-1) Page 1 of 11

EFFECTIVE DATE The 2013 IBS & Regulated Non-Executive Incentive Plan (the “Plan”), shall become effective on January 1, 2013. The Plan shall operate on the basis of a plan year that will begin on January 1, 2013 and will end on December 31, 2013 (the “Plan Year”). Payouts will be based on Plan Year performance results, except as otherwise provided herein. PURPOSE The Plan provides eligible employees with an opportunity to receive cash short term incentive compensation based upon the achievement of short-term goals that support Integrys Energy Group, Inc. (the “Company”), and those direct and indirect subsidiaries of the Company that have been designated by the Company for participation in this Plan. The purpose of the Plan is to focus eligible employees on reducing the costs of operations, improving reliability to customers, and supporting an emphasis on safety in all we do. Payouts for Plan participants will be determined based on the Plan provisions and the results of performance measurements from Participating Subsidiaries (as defined below). ELIGIBILITY Eligibility is limited to employees who are classified by the Company or a Participating Subsidiary as active regular administrative full-time or part-time employees of the Company or a Participating Subsidiary for the period of time during the Plan Year that they are employed in an eligible classification. Employees of the Company’s non-regulated direct and indirect subsidiaries, including Integrys Energy Services, Inc., are not eligible to participate in the Plan. Further, employees who participate in another short-term Company or Participating Subsidiary incentive plan (other than a plan that compensates the employee on a commission basis) are not eligible to participate in this Plan with respect to the portion of the Plan Year that is also covered under such other plan. Performance measures, weightings and threshold, target and superior payout levels by pay grade are listed in the Plan Appendix. Employees who are covered by a collective bargaining agreement, assigned by the Company to a limited term or temporary status (e.g. limited-term employees) and persons who provide services to the Company or a Participating Subsidiary but who are classified as non-employee service providers (e.g. contractors and consultants) are not eligible for the Plan. Any employee who first becomes eligible and is added to the Plan after the start of the Plan Year will be eligible to participate with respect to that Plan Year, but any payout under the Plan will be based solely on the employee’s Pay during the portion of the Payroll Year (as defined below) for which the employee was employed in an eligible classification. If an employee transfers during the Plan Year from employment covered by a collective bargaining agreement to employment in a regular position eligible for participation in the Plan, or vice versa, the employee will be eligible to participate with respect to that Plan Year, but any payout under the Plan will be based on the employee’s Pay during the portion of the Payroll Year for which the employee was employed in an eligible classification.



Except as provided in the Employment Termination section below, employees must be actively employed through December 31 of the Plan Year to be eligible for a payout under the Plan with respect to that Plan Year. Those who are not actively employed through December 31 of the Plan Year for reasons other than retirement, disability, approved leave of absence or death, will not be eligible to receive a payout from the Plan. An employee does not earn a right to a Plan payment (whether on a pro rata basis or otherwise) based upon length of service or mere completion of service during the Plan Year. Rather, a payout is earned based upon the achievement by the applicable Participating Subsidiary (or other business unit) of pre-determined performance goals measured over the course of the entire Plan Year as a result of the efforts of eligible employees who contribute toward the achievement of such goals. An employee’s participation in the Plan, and the opportunity to earn a payout in accordance with the terms and conditions of the Plan, does not represent an unequivocal promise on the part of the Company to pay incentive compensation other than to the extent that applicable performance goals have been satisfied and the employee satisfies the eligibility conditions specified herein. Eligible Plan participants who during the Plan Year change employment status from one eligible status to another eligible status but qualify to participate in the current Integrys Pay Protection policy will be eligible to participate (a) at the annual incentive percentage target level payout that has been assigned to their prior, higher pay grade with respect to eligible employment during the portion of the Plan Year that is prior to the Change in Status Date and (b) at the annual incentive percentage target level payout that has been assigned to their new, lower pay grade with respect to eligible employment during the portion of the Plan Year that is on or after the Change in Status Date. PARTICIPATING SUBSIDIARIES The participating subsidiaries (each, a “Participating Subsidiary”, and collectively, the “Participating Subsidiaries”) are: Integrys Business Support LLC (IBS), Minnesota Energy Resources Corporation (MER), Michigan Gas Utilities, Inc. (MGU), North Shore Gas Company (NSG), the Peoples Gas Light & Coke Company (PGL), Upper Peninsula Power Company (UPPCO), Wisconsin Public Service Corporation (WPS) and any other corporation or entity designated by the Chief Executive Officer of the Company (the “CEO”) for participation in the Plan. When evaluating performance during the Plan Year, the performance of all such Participating Subsidiaries shall be included. In the event that any such Participating Subsidiary is sold or otherwise divested during the Plan Year, the target metric and actual performance for such Participating Subsidiary will include the full period prior to such sale or divestiture and thereafter performance of such Participating Subsidiary will be excluded. Unless the CEO determines otherwise, in the event of an acquisition of a new subsidiary or other corporate transaction involving the merger with or acquisition of a business by TEG, performance related to such acquired business shall not be considered when evaluating performance for the Plan Year. As such, when evaluating IBS performance during the year, the respective weighting percentages assigned to each Participating Subsidiary shall be adjusted as necessary, consistent with the language above.



PAYROLL YEAR The Payroll Year that is associated with the Plan Year, that will be used to determine eligible Pay for payout calculations, is from December 23, 2012 through December 21, 2013. EMPLOYMENT TERMINATION Termination of employment at any time during the Plan Year (other than termination on account of retirement, death, or because the employee left the company in good standing at the end of a “Regular with an end date” assignment) will disqualify the participant from receiving a payout from the Plan.

Absence from active employment during the Plan Year on account of disability or approved unpaid leave of absence will not disqualify the participant from receiving a payout of any award that has otherwise been earned, but the amount payable to or on behalf of the participant will be based upon the participant’s Pay that is recognized for purposes of the Plan. Similarly, if termination of employment occurs during the Plan Year due to retirement, or death, or because the employee left the company in good standing at the end of a “Regular with an end date” assignment, the participant will receive a payout of any award that has otherwise been earned, but the amount payable to or on behalf of the participant will be based upon the participant’s Pay during the participant’s period of active service during the year.

“Retirement” means termination of a Participant’s service with the Company and its Affiliates, if one or more of the following conditions is satisfied:

(a) the termination occurs on or after the Participant's attainment of age sixty-two (62), (b) the termination occurs on or after attainment the Participant's attainment of age fifty-five (55) and completion of at least ten (10) years of vesting service (as defined in the 401(k) plan that is applicable to the participant), or

(c) in the case of a Participant who is covered under a defined benefit pension plan maintained by the Company or an Affiliate, the termination qualifies the Participant’s for retirement (as opposed to vested termination) benefits under such defined benefit pension plan.

The word “disability” means that the participant’s active service has been interrupted as a result of the participant being totally disabled (as defined in the Company’s or Participating Subsidiary’s long-term disability plan applicable to the employee). In all cases, eligibility for any earned payout is based upon the employee’s Pay during the portion of the Payroll Year for which the employee was employed in an eligible classification. Any earned Plan payout to or on behalf of a participant who terminated employment during the Plan Year on account of retirement, death, or because the employee left the company in good



standing at the end of a “Regular with an end date” assignment, or who is absent from active service on account of disability or an approved unpaid leave of absence, will be paid at the same time as payment is made to active employees whose employment with the Company or a Participating Subsidiary has continued. In the event of a participant’s death, any earned Plan payout will be distributed at such time in a lump sum to the participant’s estate. DEFINITION OF PAY Plan payouts are expressed and calculated as a percentage of the eligible employee’s Pay for the Payroll Year or applicable portion of the Payroll Year while a Plan participant. For the purposes of the Plan, “Pay” is defined as base pay and overtime earnings from the Company actually paid (or that would have been payable except for the employee’s election to defer receipt of base pay earnings) during the Payroll Year or applicable portion of the Payroll Year for services performed in an eligible employment position (including short term salary continuation or short-term disability benefits or paid leave of absence earnings paid by the Company or a Participating Subsidiary). All other payments such as, without limitation, long-term disability or other sickness or disability benefits not paid by the Company or a Participating Subsidiary, reimbursed expenses, termination pay, relocation allowances or reimbursements, deferred compensation (other than base pay earnings voluntarily deferred during the Plan Year at the election of the employee), pension restoration, supplemental retirement or similar accruals or benefits, stock options, performance shares, restricted stock, restricted stock unit or other equity compensation, retention agreements/bonuses, signing bonuses, and any contributions paid by the Company to any employee benefit plan (within the meaning of ERISA), and imputed income resulting from participation in a Company or Participating Subsidiary benefit or compensation program, shall be excluded. Only amounts paid by the Company or a Participating Subsidiary and otherwise eligible in accordance with the foregoing provisions of this paragraph will be recognized as pay; other payments and benefits, e.g., long-term disability benefits paid by a third party insurer, are not recognized as Pay. PLAN PERFORMANCE MEASURES Plan payouts will be based on the various Company, NSG, PGL, MER, MGU, UPPCO, and WPS operational performance measures. Each goal is weighted, representing a proportional share of the potential payout. No payout will be made with respect to a particular performance goal if performance with respect to that goal does not exceed the threshold level of performance. To receive a target award for a goal, the target performance goal level must be attained. To receive a superior award for a goal, the superior performance goal level must be attained. For performance that exceeds threshold but is less than target or greater than target but less than superior the payout amount will be pro-rated. IBS will share outcomes of the regulated utility subsidiaries on a prorated basis as related to Customer Satisfaction, Employee Safety and the various reliability measures. The respective weighting percentages by Participating Subsidiary for the Plan Year are: MER 4.76%, MGU 3.82%, NSG 5.05%, PGL 34.15%, UPPCO 4.11% and WPS 48.11%. These weightings will be used to calculate IBS payouts. General descriptions of the performance measures to be utilized in determining payouts for the Plan Year are set forth below. Not every performance measure applies with respect to each



Participating Subsidiary or each eligible employee of a Participating Subsidiary, nor will the weightings applied with respect to a performance measure necessarily be the same between Participating Subsidiaries or between employee groups who are employed at a particular Participating Subsidiary. In addition, the performance measures can be specific to a group, and may include measures as approved by the CEO. OPERATIONAL MEASURES Integrys Energy Group-Utility and IBS FERC-based non-fuel Operation and Maintenance expense – Adjusted Before Annual Incentives The annual forecasted Combined Utility and IBS FERC-based non-fuel Operation and Maintenance (O&M) expense – Adjusted Before Annual Incentives is determined based upon the combined Utility and IBS FERC-based non-fuel O&M included in the budget accepted by the Integrys Board of Directors on December 12, 2012 adjusted for:

(1) Budgeted annual incentive plan compensation expense, expected to be accrued at

target-level performance related to the executive and non-executive annual incentive compensation plans for employees of IBS and the Regulated Utilities,

(2) Amounts recorded for (a) costs recovered directly through regulatory trackers

such as bad debt, demand side management, energy efficiency programs, and manufactured gas plant clean up, (b) electric transmission (wheeling) costs, and (c) bad debt expense not recovered through trackers.

(3) The performance levels required to achieve threshold, target, and maximum

payout levels for performance on Combined Utility and IBS FERC-based non-fuel Operations and Maintenance (O&M) expense-Adjusted Before Annual Incentives are attached in Appendix A hereto.

The Calculated Combined Utility and IBS FERC-based non-fuel Operation and Maintenance expense – Adjusted Before Annual Incentives used to determine if desired performance has been achieved will be calculated based upon the combined Utility and IBS FERC-based non-fuel O&M included in the final 2013 audited financial results for Integrys Energy Group, Inc. adjusted for:

(1) Incentive plan compensation expense included in the actual results related to the executive and non-executive annual incentive compensation plan for employees of IBS and the Regulated Utilities,

(2) Where applicable to O&M, the pre-tax impact of adjustments reflected in Integrys

Energy Group’s 2013 EPS-Adjusted as reported in the Company’s earnings release for fiscal year 2013, and



(3) Amounts recorded for (a) costs recovered directly through regulatory trackers such as bad debt, demand side management, energy efficiency programs, and manufactured gas plant clean up, (b) electric transmission (wheeling) costs, and (c) bad debt expense not recovered through trackers, and

(4) Budget to actual variances for costs related to various long term equity-based

incentive compensation arrangements for plan participants who are employees of IBS and the Regulated Utilities (in order to avoid incentive arrangements that would reward employees under the annual incentive plan for a declining stock price, etc.).

Customer Satisfaction Measure The continued success of the Company will ultimately be determined by our customers, requiring customer satisfaction to be the focal point of our efforts. Customer satisfaction will be measured for residential customers of MERC, MGU, NSG, PGL, UPPCO and WPS and compared against the satisfaction survey results of other regional benchmark energy suppliers. Surveys will be conducted by J.D. Power and Associates. The surveys measure overall customer satisfaction in categories such as power quality and reliability, communications, corporate citizenship, price, billing and payment, customer service and field service. Survey category results are combined into an overall score for each utility. The incentive measure compares each of our electric and gas utilities’ score against the Midwest regional average utility score. IBS employees’ incentive measure will be a weighted combination of all of our utilities’ scores – the score weighting based on the ratio of customer counts for each utility. Employee Safety Employee safety will be measured with a rate calculated by multiplying the number of recordable cases over a given period of time by 200,000. That total is subsequently divided by the number of total hours worked by the identified business unit to obtain the final rate. An injury or illness is considered recordable if it meets standard criteria set by Occupational Safety and Health Administration (OSHA) regulations. For purposes of determining results for 2013, the rate is measured over a calendar year basis. The recordable incident rates are further analyzed against viable industry benchmarks, and final targets are reviewed and approved by business unit management to promote consistency and improvement. Regulated utility subsidiaries – measure will rely on the individual metrics of MER, MGU, NSG, PGL, UPPCO and WPS. IBS employees will use each utility’s score as a portion of their score, weighted to reflect the ratio of IBS costs allocated to the utility. This incentive is designed to promote safety awareness and safe work practices and will not be the cause of underreporting of injuries and illnesses. VARIABLE OPERATIONS RELIABILITY MEASURES (see below) IBS employees will use each utility’s score as a portion of their score, weighted to reflect the ratio of IBS costs allocated to the utility.



UPPCO, WPS - System Reliability The System Reliability measure includes two components, electric system and gas system reliability which measure our ability to deliver quality services to our customers by reducing the frequency and duration of planned and unplanned service interruptions. The electric system component will apply to UPPCO and WPS. The gas system component will apply to WPS. They are defined as follows: The electric system measurement is the annual System Average Interruption Duration Index (SAIDI), excluding major event days as defined by the IEEE (Institute of Electrical and Electronics Engineers) Standard 1366-2003. The SAIDI is the cumulative customer minutes of outage, on average, per customer served per year. It excludes the customer minutes of outage due to major event days such as large storms, and includes the customer minutes of outage due to events originating on the transmission, substation, and distribution systems. The 2013 incentive levels of threshold, target and superior are determined by the historical average annual SAIDI values. The gas system component measure is based on the percentage of customer and public odor complaints with employee response times less than or equal to 60 minutes. PGL - Reduction in Class 2 System Leaks A Class 2 leak is a gas leak that is recognized as being non-hazardous at the time of detection, but justifies more frequent monitoring and scheduled repair based on probable future hazard. Proper management of Class 2 gas leaks will reduce exposure to risk. There would also be some cost savings through the reduction in frequency of future required leak rechecks. The metric for this measure will be based on the percentage of Class 2 gas leaks pending repair as a ratio to the total number of Class 2 and Class 3 pending repair. A Class 3 leak is one that is nonhazardous at the time of detection and can be reasonably expected to remain non-hazardous. NSG – Reduction in Total Leaks Leaks not requiring immediate action are recognized as being non-hazardous at the time of detection. However these non hazardous leaks require frequent monitoring and scheduled repair based on probable future hazard. Reducing the total number of non-hazardous leaks pending reduces the risk of leak migration between rechecks and improves overall system safety. There is also cost savings when expediently repairing leaks through the reduction in the number of rechecks required to be performed. The metric for this measure would be the total number of leaks pending. The results would be measured as an average of the total leaks pending repair on the last day of each month. NSG, PGL - Reduction in 2nd and 3rd Party Damages Damage prevention is an operational measure with a significant safety component and will be critical for development of a strong distribution integrity management program. Elimination of third party damages is a major initiative across the natural gas industry. Reducing damages by others to company gas facilities improves safety for our own employees as well as for the general



public and avoids outages to our customers. The metric for this measure will be based on the total number of excavation damages caused by second parties (company contractors) and third parties (other excavators) to company-owned facilities per 1,000 locates performed by the company. NSG, PGL – Reduction in Damages caused by Company Crews Installing and maintaining natural gas facilities requires company crews to work in close proximity to other utilities. Performing this work safely is essential to ensure employee and customer safety. This can be achieved by proper jobsite preparedness and safe excavation practices. Cost savings can also be achieved through reduced claim expenses. The metric for this measure will be the number of damages caused by company crews to other utilities, below and above ground, as well as to company facilities. MER - Meter Set Remediation This multi-year metric is based on meter set remediation as identified in MERC’s meter set surveys. For 2013 the measure will focus on risers in hard surface; in 2012 the measure focused on stop valve readily accessible; in 2011 the measure focused on active atmospheric corrosion. The remediation targets are number of meter sets remediated based on budget and resources. MGU - Meter Valve Remediation This metric is based on improving performance of defective meter shut-off valve corrections. The objective is to reduce the number of outstanding broken, buried, and built over meter shut-off valves. Completion goal is the percent corrections of all identified defective shut-offs found in 2012 and prior – 35% for threshold, 50% for target, and 75% for superior performance. WPS - Market Effectiveness Measure The WPS Market Effectiveness measure is specific to WPS Energy Supply Operations participants, and selected participants in Energy Supply & Control. It is based on the energy price weighted availability of all WPS’s generation facilities, the comparison of what WPS electric generation earns in 2013 versus what it could have earned if all units had been available 100% as needed. PAYMENT OF INCENTIVE AWARD EARNED The President of the Company or of a Participating Subsidiary (or, if there is no President of a Participating Subsidiary, the highest ranking officer of the Participating Subsidiary) shall have discretion to determine that an eligible employee of the Company or applicable Participating Subsidiary is ineligible in total or in part for a Plan payout if the employee has earned less than a “fully successful” performance evaluation rating for the Plan Year or is otherwise being counseled concerning documented insufficient performance. This is the only circumstance in which an amount that would otherwise be payable as a result of the achievement of performance objectives might not be paid assuming employment continues through the end of the Plan Year.



PLAN PAYOUTS Following the close of the Plan Year and after the audited financial results are available, the CEO will certify the extent to which the performance measures have been satisfied and will authorize Plan payouts. Payouts, less tax withholdings, will be paid no later than March 15th of the year following the Plan Year. No payout will be made with respect to a particular performance measure if performance with respect to that measure does not exceed the threshold level of performance. To receive a target payout for a measure, the target performance level must be attained. To receive a superior payout for a measure, the superior performance level must be attained. An employee who during the Plan Year changes employment status from one regular eligible status or position to another regular eligible status or position, other than a change that the Company or applicable Participating Subsidiary determines to be short-term or temporary assignment that does not represent a long-term change in the employee’s regular role, will be subject, with respect to employment on or after the date the change in employment status is reflected in the PeopleSoft System (the “Change in Status Date”), to the Plan payout target and/or incentive measures applicable to the employment status into which the employee has transferred. Any payout applicable to eligible employment during the Plan Year prior to the Change in Status Date will be based upon the employee’s payout targets and/or incentive measures applicable to the employee prior to the Change in Status Date and the employee’s pay prior to the Change in Status Date. Any payment applicable to eligible employment during the Plan Year but on or after the Change in Status Date will be based upon the employee’s payout target and/or incentive measures applicable to the employee on or after the Change in Status Date and the employee’s Pay on or after the Change in Status Date. In the case of a regular employee who during the Plan Year changes employment status from a regular eligible status and position to a Developmental position, the foregoing rules will apply, except that with respect to employment on or after the Change in Status Date, the employee will retain the Plan payout target applicable to the employee’s original regular eligible status and position but any incentive payout to the employee will be determined under the Plan incentive measures of the Developmental position organization. Legacy short-term or other temporary assignments (as determined by the Company or applicable Participating Subsidiary) will not change the incentive plan or level that an employee is assigned to. The employee will remain in his or her regular role for payout calculation purposes. RELATIONSHIP TO OTHER COMPANY PLANS Employees who participate in another short term incentive plan (for example, an incentive plan at Integrys Energy Services, Inc.) are not eligible to participate in this Plan until the time their participation in the other short term incentive plan terminates.



RIGHTS OF PARTICIPANTS & FORFEITURE Nothing in this Plan shall:

(1) Confer upon any employee any right with respect to continuation of employment with the Company;

(2) Interfere in any way with the right of the Company or the Participating Subsidiaries or any other affiliate to terminate his/her employment at any time; or

(3) Confer upon any employee or any other person any claim or right to any distribution under the Plan except to the extent that a payment has been earned based upon the achievement of the measures applicable to the employee and the employee otherwise satisfies the eligibility requirements of the Plan.

No right or interest of any employee in the Plan shall, prior to actual payment or distribution to the employee, be assignable or transferable in whole or in part, either voluntarily or by operation of law or otherwise, or be subject to payment of debts of any employee by execution, levy, garnishment, attachment, pledge, bankruptcy, or in any other manner.

ADMINISTRATION

The Compensation Committee of the Board of Directors has delegated to the CEO its authority and responsibility with respect to the Plan. Accordingly, the CEO is authorized to 1) interpret and apply the Plan’s terms and conditions, 2) determine who will participate in the Plan and the level of participation, and 3) approve, within the first 90 days of the Plan Year, the performance measures that are applicable to a covered employee’s participation. The CEO’s authority does not include the authority to 1) modify the performance measures once initially established and approved within the first 90 days of the Plan Year, or 2) to adjust payout amounts that have been earned under the Plan provisions.



STATE OF MICHIGAN



DIRECT TESTIMONY & EXHIBITS OF

CHARLES F. HAUSKA

FOR


June 7, 2013

- 2 -

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

CHARLES F. HAUSKA PART I


A. My name is Charles F. Hauska. My business address is 899 S. Telegraph, Monroe, 2

Michigan 48161. I am Operating Vice President for Michigan Gas Utilities 3

Corporation (“MGUC”). MGUC is a wholly-owned subsidiary of Integrys Energy 4

Group, Inc. (“Integrys”). 5

6



9

Q. Briefly describe your educational, professional, and utility background. 10

A. I received a Bachelor of Science degree in mechanical engineering from Tri-State 11

University in Angola, Indiana, in 1981 and became a licensed professional engineer 12

in the state of Michigan in 1989. I also attended the Public Utility Executive Program 13

at the University of Michigan in 1987. I have been employed by MGUC, or its 14

predecessor company, since 1973. I have held various supervisory and managerial 15

positions in operations, engineering and network management. 16

17

18

- 3 -


A. Yes. I have testified before the West Virginia Public Service Commission, the 2

Minnesota Public Utilities Commission and the Michigan Public Service Commission 3

(“Commission”). 4

- 4 -

CHARLES F. HAUSKA DIRECT TESTIMONY

PART II

Q. What is the purpose of your testimony? 1

A. The purpose of my testimony is to discuss capital investments over $500,000, as 2

well as explain Known & Measurable (“K&M”) expenses associated with certain 3

Operating and Maintenance (“O&M”) accounts. 4

5


A. Yes, I am. I am sponsoring the following exhibits: 7

1. Exhibit A-2 (CFH-1), Schedule B5, 8

2. Exhibit A-3 (CFH-2), Schedules C16 – C21, 9

10

Q. Did you cause these exhibits to be prepared? 11

A. Yes, I did. 12

13

Capital Investments Over $500,000 14 Q. Please describe Schedule B5 of Exhibit A-2 (CFH-1). 15

A. Schedule B5 of Exhibit A-2 (CFH-1) identifies the capital projects with expenditures 16

greater than $500,000 forecasted from July 2012 through December 2014. These 17

expenditures were forecasted in our 2013 budget process which was prepared in the 18

fall of 2012. 19

20

Q. Please continue. 21

A. In 2012, MGUC had only one project that exceeded $500,000. This project was a 3 22

mile, 10” steel transmission line in the Coldwater area. Its total cost was 23

approximately $2.3 million. 24

25

- 5 -

Q. What was the purpose of this project? 1

A. The purpose of this project was to address reliability and safety concerns regarding a 2

segment of existing 10” steel transmission line installed in 1950 that traversed 3

through the City of Coldwater at a Maximum Allowable Operating Pressure (“MAOP”) 4

of 720 pounds per square inch (“psi”). This segment was identified for replacement 5

for several reasons. First, it passed through residential areas, as well as several 6

High Consequence Areas (“HCA”) containing a school, churches, and a prison. (An 7

HCA is an area flagged pursuant to U.S. Department of Transportation Pipeline & 8

Hazardous Materials Safety Administration (“PHMSA”) regulations as being of 9

special concern due to high population density or the presence of occupied 10

structures that would be difficult to evacuate.) Additionally, during “dig-ups” required 11

by PHMSA pipeline integrity management rules, MGUC discovered areas of 12

damaged and dis-bonded coating indicating degraded material integrity. Finally, 13

MGUC has also experienced leakage on welds along this segment. 14

15

Q. How did the new pipeline address these situations? 16

A. The existing pipeline segment was replaced by constructing a new transmission line 17

segment around the outskirts of Coldwater. The new segment allowed MGUC to 18

maintain the pressures and volumes required to serve the Coldwater area while 19

reducing the pressure on the existing segment to approximately 300 psi. The new 20

transmission line segment also was routed to avoid the HCAs, which provided for a 21

safer and more reliable distribution system for the City of Coldwater. The new 22

pipeline segment was placed in service by December 31, 2012. 23

24

Q. What is the next capital item you will be addressing? 25

A. The next item is a transmission project currently under construction in the Monroe 26

area. It has a total project cost of $4,000,000. 27

- 6 -

1

Q. Please continue. 2

A. Similar to the Coldwater project, the Monroe project involves a segment of 12” 3

transmission line that was installed in 1950 and which operates at approximately 450 4

psi. The existing Monroe transmission line traverses through an industrial park 5

containing HCAs, as well as a commercial and residential area. It also includes 6

casings at street and railroad crossings that are required to be replaced by federal 7

PHMSA regulations. MGUC conducted pipeline integrity management investigations 8

of this segment of the Monroe transmission line and discovered numerous safety 9

concerns, including pipe coating faults, shallow depths of less than 12”, and dents 10

and other damages to the pipe (caused by third parties over the years). 11

12

Q. How will the new pipeline address reliability and safety concerns? 13

A. The new pipeline will be re-routed along the perimeter of the industrial area to avoid 14

HCAs to the greatest extent practicable, and it will be constructed to today’s material 15

and construction standards, which will allow it to operate as a high pressure 16

distribution line. The existing main will be retired. Construction of this project is 17

scheduled to begin in June 2013 and be completed by year end. 18

19

Known & Measurable Items 20 Q. Please describe Schedule C16 of Exhibit A-3 (CFH-2). 21

A. Schedule C16 of Exhibit A-3 (CFH-2) displays the increase of $70,502 in FERC 22

Account 819, Compressor Station Fuel associated with underground Storage. 23

During the 2012 Historic Test Year, MGUC only filled a portion of its company owned 24

storage reservoirs. This was due to not depleting working volumes during the 25

withdrawal season because of significantly warmer than normal weather, as well as 26

not filling a reservoir that was shut-in for an18-month engineering test. The revised 27

amount anticipates compressor fuel required to fill storage to a level consistent with 28

- 7 -

GCR customer requirements during normal winter weather conditions. 1

2

Q. Please describe Schedule C17 of Exhibit A-3 (CFH-2). 3

A. Schedule C17 of Exhibit A-3 (CFH-2) displays an increase of $80,000 in FERC 4

Account 832, Maintenance of Reservoirs and Wells. MGUC has established a 5

program for periodically performing logs on the Company’s injection and withdrawal 6

wells associated with its underground storage reservoirs. These logs examine the 7

integrity of the well casings with respect to defects caused by corrosion as well as 8

ensuring bonding of cement to the casing to eliminate potential migration of gas 9

along the casing if a leak occurred. In 2012, MGUC performed capital work 10

associated with rebuilding some of these injection/withdrawal wells. The typical 11

logging program was unnecessary for the rebuilt wells, which decreased the amount 12

of O&M in 2012 from that which was historically spent. In 2013 and beyond, MGUC 13

will return to the regular program performing logs on the injection and withdrawal 14

well, which will require O&M funding beyond the inflated 2012 amount spent. 15

16



Account 880, Other Expenses. The primary reason for these additional costs are 19

O&M expenses associated with MGUC owned office buildings. 20

21

Q. Please explain the reasons for these additional O&M expenses. 22

A. MGUC owns five district office facilities located in Grand Haven, Benton Harbor, 23

Otsego, Coldwater and Monroe. It also has office and plant facilities located at the 24

underground storage operations in Partello. The Coldwater, Benton Harbor and 25

Grand Haven facilities were built approximately 20 years ago. Up to this point, there 26

have been very few renovations and limited maintenance performed on the buildings 27

- 8 -

because the facilities were relatively new. However, there are numerous issues 1

beginning to rise that need to be addressed to keep the buildings in proper repair. 2

This includes interior and exterior painting, cracks in mortar joints, parking lot repairs, 3

minor HVAC repairs, and electrical updates. MGUC’s Monroe facilities were built in 4

1978 and 1981. These two buildings and associated grounds are also in need of 5

repairs and maintenance beyond what has been spent in recent years. Without the 6

increase in spending on maintenance, all of these buildings will fall into a level of 7

disrepair that will require major capital expenditures to replace components. MGUC 8

has begun a program in 2013 to address these issues that were not included in the 9

2012 historic test year. Specifically, at the Coldwater facility, we have done interior 10

wall repairs, painting, and floor maintenance and are in the process of evaluating 11

lighting upgrades for energy conservation. We are evaluating necessary exterior 12

repairs as well. These types of projects are also planned for the Benton Harbor and 13

Grand Haven facilities, given the similar age and construction of the buildings. The 14

Company is budgeting to spend $250,000 per year for the next several years to keep 15

these facilities in a proper state of repair. 16

17

Q. Please describe Schedule C19 of Exhibit A-3 (CFH-2) and Schedule C21 of 18

Exhibit A-3 (CFH-2). 19


Account 885, Operations Supervision and Engineering Expenses and Schedule C21 21

of Exhibit A-3 (CFH-2) displays an increase of $505,000 in FERC Account 902, 22

Meter Reading Expenses. 23

24

Q. Please explain the reasons for the increase in Account 885. 25

A. In the past, MGUC has experienced an employee attrition rate of approximately 2% 26

per year. During the 2012 historic test year, MGUC experienced an unprecedented 27

- 9 -

employee turn-over of approximately 13%. This included Network Operations 1

Supervisor positions in Benton Harbor and Coldwater, a Customer Operations 2

Supervisor in Coldwater and a Cathodic Protection Technician in Benton Harbor. 3

Due to the time lag associated with recruiting and hiring, these positions were vacant 4

for several months at a time. Therefore, the O&M costs associated with these 5

vacancies are significantly understated in the 2012 historic test year expenses. 6

Additionally, two engineering staff positions were approved late in the year, deemed 7

necessary because of the experience and expertise that is being lost with the 8

numerous retirements occurring and pending. One of the positions was filled early in 9

2013 and the Company is currently in the process of hiring the second, so the 10

associated costs of these two engineering positions are not included in the 2012 test 11

year expenses. A Construction Coordinator position was also added in Benton 12

Harbor to address increased work load being experienced in that area. This position 13

was filled in December 2012; so again, the vast majority of the costs associated with 14

the new Construction Coordinator position are not included in the 2012 historic test 15

year. The total cost of these vacancies and added positions not included in the test 16

year expenses equates to $407,000 in account 885. 17

18

Q. Please explain the reasons for the increase in Account 902. 19

A. During 2012, MGUC experienced similar attrition in its “front line” union workforce 20

due to retirements, as well as union employees applying for non-union vacancies. 21

This caused an exorbitant amount of vacancies in the union workforce, which 22

required posting for backfilling, training, and recruiting and hiring. Most of the 23

vacancies being filled are entry-level, meter reader positions. In 2012, because of 24

these vacancies and the time required to fill and train them, MGUC experienced its 25

lowest percentage of meters being read in many years. Schedule C21, Exhibit A-3 26

(CFH-2), shows that $505,000 of additional O&M costs in FERC Account 902, Meter 27

- 10 -

Reading Expenses, and are necessary to return MGUC’s meter reading capability to 1

a level that will comply with the Commission billing rules and MGUC’s tariff. 2

3


A. Schedule C20 of Exhibit A-3 (CFH-2) displays the increase of $250,000, in Account 5

887, Maintenance of Mains. As part of MGUC’s Distribution Integrity Management 6

Program (“DIMP”), there are two areas that will be addressed that were not included 7

in 2012: (i) integrity of portions of its High Pressure Distribution system that contains 8

1950 vintage ERW steel pipe and (ii) early vintage (pre 1973) Aldyl A polyethylene 9

pipe. 10

11

Q. Why is MGUC focusing on these 2 areas? 12

A. Although MGUC has not yet experienced significant issues with the integrity of its 13

ERW steel pipe and its vintage plastic pipe, the industry as a whole has reported 14

multiple failures due to degradation of 1950 vintage ERW steel pipe and vintage 15

Aldyl A polyethylene pipe. MGUC believes in being proactive in maintaining a safe 16

and reliable system. MGUC plans to evaluate the portions of its system containing 17

these two types of main to determine if the pipe should be replaced. However, there 18

is no current funding in MGUC’s budgets for this evaluation. 19

20

Q. How does MGUC plan to evaluate the 1950 vintage ERW steel pipe? 21

A. MGUC intends to perform engineering analysis on the system in the Coldwater – 22

Sturgis area, which was installed in 1950. This system contains ERW pipe that has 23

experienced significant leakage, caused by construction defects on welds. MGUC 24

will examine the condition of the welds on sections of pipe that have been removed, 25

as well as the integrity of the seams. MGUC will also explore the potential of running 26

intelligent pigs through certain segments. 27

- 11 -

1

Q. What are MGUC’s intentions regarding its vintage Aldyl A polyethylene pipe? 2

A. MGUC has vintage Aldyl A polyethylene pipe that dates back to the late 1960’s when 3

DuPont first introduced it to the market. MGUC will retrieve samples of this older pipe 4

from various installation years and geographic locations and have lab analyses 5

performed to determine brittleness. If the analyses indicate potential failure, the 6

Company will develop a program for the replacement of this type of pipe. 7

8

Q. What are the anticipated costs of the programs you have described? 9

A. MGUC anticipates an initial cost of $250,000 per year to begin funding these 10

programs. It would potentially grow, based on the outcomes of the initial findings. 11

12


A. Yes, it does. 14

Case No.: U-17273Exhibit No.: A-2 (CFH-1)

Schedule: B5Page: 1 of 1

Witness: Charles F. Hauska

7/1 - 12/31Line Project Number Project Description 2012 2013 2014 Total

12 GAS PROJECTS3 140010003 COLDWATER, 3 MILE, 10" STEEL TRANSMISSION LINE $2,300,000 $2,300,0004 140000021 MONROE 12" TRANSMISSION LINE RELOCATION $4,000,000 $4,000,00045 TOTAL - GAS PROJECTS $2,300,000 $4,000,000 $0 $6,300,000

Michigan Gas Utilities Corporation Capital Projects with Expenditures over $500,000

Note: All values are Expenditures, not 13-month averages.




Line

1 $ 70,502

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 70,502

Account 819

2014 Costs

Michigan Gas Utilities CorporationCalculation of Storage Field Costs


2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 80,000

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 80,000

Account 832

2014 Costs

Michigan Gas Utilities CorporationCalculation of Well Logs Costs


2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 250,000

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 250,000

Account 880

2014 Costs

Michigan Gas Utilities CorporationCalculation of Building Expenses


2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 407,000

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 407,000

Account 885

2014 Costs

Michigan Gas Utilities CorporationCalculation of Non-Union Staff Vacancies


2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 250,000

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 250,000

Account 887

2014 Costs

Michigan Gas Utilities CorporationCalculation of High Risk Mains


2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation




Line

1 $ 505,000

2 $ -

3 1.708%

4 1.993%

5 3.74%

6 $ -


8 $ 505,000

Account 902

2014 Costs

Michigan Gas Utilities CorporationCalculation of Union Staff VacanciesKnown and Measurable Adjustment

2012 Costs



2013 Inflation

2014 Inflation

Composite Inflation

STATE OF MICHIGAN


* * * * * In the matter of the application of ) MICHIGAN GAS UTILITIES CORPORATION ) for authority to increase retail electric rates. ) Case No. U-17273 )


BRIAN E. KAGE

FOR


June 7, 2013

- 2 -

STATE OF MICHIGAN


* * * * *

In the matter of the application of ) MICHIGAN GAS UTILITIES CORPORATION ) for authority to increase retail electric rates. ) Case No. U-17273 )

QUALIFICATIONS OF

BRIAN E. KAGE PART I


A. My name is Brian E. Kage. My business address is Integrys Business Support, LLC 2

(“IBS”), 700 North Adams Street, P.O. Box 19001, Green Bay, WI 54307-9001. I am 3

the General Manager of Strategy and Business Performance of Integrys Energy 4

Group, Inc. (“Integrys”). Both IBS and Michigan Gas Utilities Corporation (“MGUC”) 5

are wholly-owned subsidiaries of Integrys. 6

7



10


A. I graduated from Texas Christian University with a Bachelor of Business 12

Administration in Finance. I began my career with Integrys in January 2007 as Value 13

Manager in the Corporate Development area. In April 2008, I assumed my current 14

position as General Manager of Strategy and Business Performance in the Customer 15

Relations department. Prior to working for Integrys, I worked for Accenture and 16

Black & Veatch where I provided services for North American and International 17

utilities in the areas of Customer Operations & Application Strategy, Merger & 18

- 3 -

Acquisitions Value Capture, and CIS implementations. 1

2


A. No, I have not. 4

- 4 -

BRIAN E. KAGE DIRECT TESTIMONY

PART II


A. The purpose of my pre-filed direct testimony is to describe the Integrys Customer 2

Experience ICE 2016 (“ICE 2016”) project, as well as the Intangible Benefits of the 3

ICE 2016 project to MGUC and the other five Integrys regulated utilities. 4

5


A. Yes, I am. I am sponsoring Exhibit A-3 (BEK-1), Schedule C36, consisting of 3 7

pages. 8

9


A. Yes, it was. 11

12

Q. Please describe Exhibit A-3 (BEK-1), Schedule C36 13

A. Exhibit A-3 (BEK-1), Schedule C36 summarizes the various cost and savings inputs 14

to the economic analysis used to evaluate the various options considered for the ICE 15

2016 project. These values were used in the economic analysis described in the 16

pre-filed direct testimony of Michael E. Gerth. 17

18

Q. What is the ICE 2016 project? 19

A. The Integrys family of six regulated utilities currently operate with three distinct billing 20

systems: 21

1. The “Open-C” system for WPS Corp and UPPCO, 22 23 2. The “Vertex” system for MGUC and Minnesota Energy Resources 24

Corporation (“MERC”), and 25 26 3. The “C-First” system for The Peoples Gas Light and Coke Company 27

(“PGL”) and North Shore Gas Company (“NSG”). 28

- 5 -

1

The ICE 2016 project will result in a single billing system for all six Integrys regulated 2

utilities. 3

4

Q. Other than providing a single billing system for all six Integrys regulated 5

utilities, what other features and benefits result from the ICE 2016 project? 6

A. The intangible benefits that the ICE 2016 project will provide to MGUC and the other 7

Integrys regulated utilities are improved efficiency and productivity as a result of 8

converting from the current MGUC Customer Information System (“CIS”) technology 9

platform (Vertex) onto the Open-C technology platform. 10

11

One of the most important benefits of ICE 2016 is that it will provide overall 12

standardization of internal delivery processes and system technology platforms 13

which will improve customer satisfaction, increase productivity, and increase 14

efficiency by lowering overall operating costs. 15

16

Next, ICE 2016 will improve and enhance the features of our Billing, Collections, Call 17

Center, and Self-Service related offerings by ensuring that these functions are 18

staffed appropriately to continue to leverage the opportunities of a large corporation, 19

while maintaining the high level of service of a local utility. 20

21

Further, ICE 2016 will provide a standardized process architecture and technology 22

platform that will enable the Integrys regulated utilities to achieve and sustain first 23

quartile performance in cost management (cost per customer), customer satisfaction, 24

and service quality for the Billing, Collections, Call Center, and Self Service 25

functions. Specifically, the benefits of this project include improved customer 26

experience through implementation of several improvements to our Interactive Voice 27

- 6 -

Response (“IVR”) and web self-service channels that will increase our customer’s 1

use of these channels, and reduce the number of inbound calls to our call centers. 2

These improvements include: 3

• The automation of customer turn-offs. 4 5

• The ability to schedule service appointments. 6 7

• Improved use of bill analyzer tools. 8 9

• Providing customers with web access to their bill image. 10 11

• Several usability type improvements. 12 13

• Consolidating all utilities onto a single web, telephone and IVR 14 platform. 15

16

Several improvements that will increase our first call resolution and customer 17

satisfaction include: 18

• An improved call center agent on-line encyclopedia. 19 20

• Deployment of a First Call Resolution analytical tool. 21 22

• Improved call center Q&A and agent monitoring. 23 24

• An improved complaint identification and resolution process. 25 26

Other functions that ICE 2016 will provide include: 27

• Deployment of a Credit Model which improves collections 28 performance through implementation of a customer behavioral/risk 29 score that will help to improve the efficiency and effectiveness of 30 our collection actions. 31 32

• Improved collection schedules that will work in conjunction with 33 the customer behavioral/risk score to further ensure increased 34 effectiveness of our collection actions. 35

36 • Improved enrollment processes for new customers that will secure 37

deposits for high risk customers, and implement additional steps 38 to verify customer identity, thereby reducing the number of 39 fraudulent applications. 40

41 • The reporting of customer payment behavior, both positive and 42

negative, to the Credit Bureaus. 43 44

- 7 -

• Improved processes for locating and contacting customers who 1 have finalized their account. 2

3

Finally, ICE 2016 will provide improved Billing and Payment related performance by 4

continuing to implement our strategy for: 5

• Increased e-Bill adoption. 6 7

• Making improvements in the Bill Estimation routine. 8 9

• Improving our bill printing, document imaging, and document 10 storage capabilities. 11

12 • Providing real-time electronic payment information to our Call 13

Center and Self Service channels to improve the customer 14 reconnection for nonpayment process. 15

16 • Automating the Non-Sufficient Funds check process with our 17

banks. 18 19

Q. What options were considered for the ICE 2016 project? 20

A. Option 1 assumed Integrys would consolidate from the current three CIS platforms 21

and associated business operating models to one enhanced Open-C platform that 22

will support standardized business processes for all six regulated utilities by 2016. 23

Open-C is the CIS currently used by Integrys affiliates WPS Corp and UPPCO. This 24

is known as the “3 to 1 option”. 25

26

Option 2 assumed Integrys would consolidate from three to two CIS platforms: Open-27

C for all Integrys utilities except PGL and NSG, which would remain on their currently 28

existing CIS known as C-First. Option 2 was assumed to be completed by 2015. 29

This is known as the “3 to 2 option”. 30

31

Option 3 assumed Integrys would first consolidate from three to two CIS platforms 32

(same as Option 2) by 2015, and then move to one CIS platform (Open-C) by 2018. 33

This is known as the “3 to 2 to 1 option”. 34

- 8 -

1

Q. How were the various costs used in the economic analysis derived? 2

A. For the 3 to 1 option, the various costs were developed during a Business 3

Requirements Design phase which designed all Customer Operations related 4

processes and the requirements necessary to implement those processes. Those 5

requirements were then analyzed to determine the technology changes necessary to 6

implement those processes across all six utilities. In addition, the necessary change 7

management impacts were analyzed and estimated. 8

9

For the 3 to 2 option, the various costs were developed by limiting the scope to 10

converting MGUC and MERC to the same platform as WPS Corp and UPPCO (i.e., 11

Open-C), while PGL and NSG would remain on their existing platform (i.e., C-First). 12

Limited changes to the processes in Open-C would be made to accommodate MGU 13

and MERC. 14

15

For the 3 to 2 to 1 option, the costs for the 3 to 1 option were analyzed to determine 16

the impact of an elongated schedule and two distinct implementations. 17

18

Q. How were the cost savings for the economic analysis derived? 19

A. The technology and operational costs for our current state customer operations were 20

modeled over a 15 year period from 2012 – 2026. For each of the three different 21

options analyzed, the reductions in O&M and Capital expenditures was determined 22

and applied in the appropriate year. For on-going savings, they were inflated by 23

2.7% from the year identified to 2026. 24

25

The various costs and savings for each option are summarized on Exhibit A-3 (BEK-26

1), Schedule C36. 27

- 9 -

1

MGUC’s O&M costs associated with the 2014 projected test year are included in 2

Exhibit A-3 (KAD-3), Schedules C22 and C31, which are sponsored by Ms. 3

Katherine De Cramer. 4

5


A. Yes, it does. 7

Case No. U‐17273

Witness: Brian E. Kage

Exhibit A‐3 (BEK‐1)

Schedule C36

Page 1 of 3Integrys Energy Group, Inc.ICE 2016 ProjectInputs Into Summary of Calculations of Net Present Value of Revenue Requirement ("NPVRR")

Option 1‐ Conversion from 3 Customer Information Systems to 1 by 2016

Cost To Achieve ‐ Capital

Hardware 3,201,000$

Software 5,285,000

Miscellaneous Inv. & Exp 5,208,000

Internal Labor 16,405,000

External Labor 34,237,000

Total 64,336,000$

Cost To Achieve ‐ O&M

Hardware ‐$

Software 883,000

Miscellaneous Inv. & Exp 870,000



Total 12,400,000$

Undiscounted Estimated Savings ‐ Capital

Hardware (16,709,000)$

Software (255,000)

Miscellaneous Inv. & Exp (227,000)

Internal Labor (3,064,000)

External Labor (4,595,000)

Total (24,850,000)$

Undiscounted Estimated Savings ‐ O&M

Hardware ‐$

Software (9,459,000)

Miscellaneous Inv. & Exp (124,045,000)



Cost of Capital Reduction (5,675,000)

Reduction in Bad Debt Expense (3,784,000)

Total (204,350,000)$

Case No. U‐17273



Schedule C36




Hardware 841,000$

Software 1,388,000




Total 16,807,000$


Hardware ‐$

Software 232,000




Total 3,193,000$


Hardware ‐$

Software ‐

Miscellaneous Inv. & Exp ‐

Internal Labor ‐

External Labor ‐

Total ‐$


Hardware ‐$

Software ‐


Internal Labor ‐

External Labor ‐

Cost of Capital Reduction ‐

Reduction in Bad Debt Expense ‐

Total (36,309,000)$

Case No. U‐17273



Schedule C36


Option 3‐ Conversion from 3 Customer Information Systems to 2 by 2015 and to 1 by 2018


Hardware 3,613,000$

Software 5,966,000




Total 72,549,000$


Hardware ‐$

Software 997,000




Total 13,951,000$


Hardware (16,709,000)$

Software (255,000)

Miscellaneous Inv. & Exp (227,000)



Total (24,850,000)$


Hardware ‐$

Software (7,527,000)




Cost of Capital Reduction (4,516,000)

Reduction in Bad Debt Expense (3,011,000)

Total (173,192,000)$

STATE OF MICHIGAN




MICHAEL E. GERTH

FOR


June 7, 2013

1

STATE OF MICHIGAN



QUALIFICATIONS OF

MICHAEL E. GERTH PART I


A. My name is Michael E. Gerth. My business address is Integrys Business Support 2

LLC (“IBS”), 130 East Randolph Drive, 18th Floor, Chicago, Illinois 60101. My 3

position with Integrys is Director of Finance – Gas Utility Group. Both IBS and 4

Michigan Gas Utilities Corporation (“MGUC”) are wholly-owned subsidiaries of 5

Integrys Energy Group, Inc (“Integrys”). 6

7



10


A. I graduated from the University of Cincinnati with a Bachelor of Business 12

Administration degree in Accounting and Finance. I began my career with Peoples 13

Energy Corporation in 2004 as Manager – Financial Reporting & Compliance. After 14

the merger with Integrys in 2007, I assumed my current role as Director of Finance- 15

Gas Utility Group. 16

2

MICHAEL E. GERTH DIRECT TESTIMONY

PART II


A. The purpose of my pre-filed direct testimony is to present the results of the economic 2

analysis used to evaluate the Integrys Customer Information System (“CIS”) initiative 3

known as ICE 2016 Project (“ICE”). ICE is an acronym for “Integrys Customer 4

Experience” and the project is more fully described in the pre-filed direct testimony of 5

Mr. Brian E. Kage. 6

7


A. Yes, I am. I am sponsoring Exhibit A-3 (MEG-1), Schedule C37, consisting of 1 9

page. 10

11


A. Yes, it was. 13

14

Q. Please describe Schedule C37 of Exhibit A-3 (MEG-1). 15

A. Exhibit A-3 (MEG-1), Schedule C37 is a summary of the financial assumptions, 16

inputs and results for various options considered for the ICE project. 17

18

Q. What economic analysis method was used to evaluate the ICE project? 19

A. A net present value of revenue requirements (“PVRR”) analysis for all of Integrys’ 20

regulated utility customers, discounted to 2012, was developed taking into account 21

the applicable projected costs, projected savings, accounting treatment, and 22

recovery period. Three options were examined. 23

24

3

Option 1 assumed Integrys would consolidate from the current three CIS platforms 1

and associated business operating models to one enhanced Open-C platform that 2

will support standardized business processes for all six regulated utilities by 2016. 3

Open-C is the CIS currently used by Integrys affiliates Wisconsin Public Service 4

Corporation (“WPSC”) and Upper Peninsula Power Company (“UPPCO”). 5

6

Option 2 assumed Integrys would consolidate from three to two CIS platforms: Open-7

C for all Integrys utilities except The Peoples Gas Light &Coke Company (“PGL”) 8

and North Shore Gas Company (“NSG”), which would remain on their currently 9

existing CIS known as C-First. Option 2 was assumed to be completed by 2015. 10

11

Option 3 assumed Integrys would first consolidate from three to two CIS platforms 12

(same as Option 2) by 2015, and then move to one CIS platform (Open-C) by 2018. 13

14

The impact of ICE under all three options was considered through the year 2026, 15

representing a 15-year horizon starting in 2012. 16

17

Q. Why was a PVRR analysis selected? 18

A. A PVRR analysis was selected because a PVRR analysis best models the cost and 19

savings impacts to Integrys’ regulated utility customers over the 15-year period. 20

21

Q. What was the basis for the cost estimates used in the economic analysis for 22

ICE? 23

A. The undiscounted cost and savings estimates for the three options under ICE were 24

provided to me by Mr. Brian E. Kage. The development of those undiscounted cost 25

and savings estimates is described in his pre-filed direct testimony. 26

27

4

Q. What were the results of your economic analysis? 1

A. The results are shown on Exhibit A-3 (MEG-1) Schedule C37. In short, the 2

economic analysis resulted in a PVRR net savings of $37.2 million for Option 1, a 3

PVRR net cost of $1.4 million for Option 2, and a PVRR net savings of $19.7 million 4

for Option 3. 5

6

Q. Why are there no capital expenditure savings under Option 2? 7

A. Integrys is not expecting any significant avoided capital expenditures because Option 8

2 is not a significant change from the current environment. That is, Integrys affiliates 9

MGUC and Minnesota Energy Resources Corporation (“MERC”) would be converted 10

to the same platform as WPSC and UPPCO (i.e., Open-C), while PGL and NSG 11

would remain on their currently existing platform (i.e., C-First). 12

13

Q. What were your conclusions? 14

A. Execution of Option 1 will produce the greatest net savings to Integrys’ regulated 15

utility customers over the 15 year period from 2012 through 2026. MGUC’s 16

Operations and Maintenance costs associated with the 2014 projected test year are 17

included in Exhibit A-3 (KAD-3), Schedules C22 and C31, which are sponsored by 18

Ms. Katherine De Cramer. 19

20

Q. Does this complete your pre-filed direct testimony?21

A. Yes, it does. 22

Case No. U‐17372

Witness: Michael E. Gerth

Exhibit A‐3 (MEG‐1)

Schedule C37

Page 1 of 1

Integrys Energy Group, Inc.ICE 2016 ProjectSummary of Calculations of Net Present Value of Revenue Requirement ("NPVRR")


NPVRR:

Capital Expenditures 58,779,000$

Operating & Maintenance Expense 10,179,000

Capital Expenditure Savings (15,548,000)

Operating & Maintenance Expense Savings (90,565,000)

NPVRR (Savings) Cost (37,155,000)$

Undiscounted Estimated Costs and Savings:





Total Undiscounted (Savings) Costs (152,464,000)$


NPVRR:



Capital Expenditure Savings ‐


NPVRR (Savings) Cost 1,353,000$




Capital Expenditure Savings ‐



Option 3‐ Conversion from 3 Customer Information Systems to 2 by 2015 and to 1 by 2018

NPVRR:





NPVRR (Savings) Cost (19,716,000)$







STATE OF MICHIGAN




TRACY L. KUPSH

FOR


June 7, 2013

1

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

TRACY L. KUPSH PART I


A. My name is Tracy L. Kupsh. My business address is Integrys Energy Group, Inc. 2

(“Integrys”), 700 North Adams Street, P.O. Box 19001, Green Bay, WI 54307-9001. I 3

am the Director – Operations Accounting for Integrys Business Support, LLC (“IBS”). 4

I am testifying on behalf of Michigan Gas Utilities Corporation (“MGUC”) in support of 5

MGUC’s application in this proceeding for authority to adjust its natural gas rates. 6

7

Q. Please describe your educational, professional, and utility background. 8

A. I graduated from Lakeland College of Sheboygan, Wisconsin in 1996 earning a 9

Bachelor of Arts degree with a major in Accounting and a minor in Economics. After 10

spending 19 years working for Unilever, a world wide consumer goods company, in 11

various cost accounting positions, I accepted my current position with IBS on 12

December 1, 2008. 13

14

My duties and experience as Director - Operations Accounting for IBS include the 15

review and approval of the IBS monthly financial statements, overseeing the proper 16

allocation of the IBS costs to the affiliates, the coordination and/or participation in the 17

2

preparation of the IBS Operation & Maintenance (“O&M”) and Capital budgets, and 1

the analysis of variances between forecasted and actual financial results of IBS. 2

3

TRACY L. KUPSH DIRECT TESTIMONY

PART II


A. The purpose of my pre-filed direct testimony is to describe the services provided by 2

IBS under the Master Regulated Affiliated Interest Agreement (“Regulated AIA”) 3

between IBS and its regulated utility affiliates. In this testimony I will: 4

1. Provide an overview of the basic philosophy and goals of IBS’s business 5 operations, 6

7 2. Describe the corporate structure of IBS and the services IBS provides to its 8

affiliates, and 9 10

3. Describe the various cost allocation methodologies and formulas that 11 determine the costs paid by Integrys affiliates for the services provided by 12 IBS. 13

14

Q. Are you sponsoring any exhibits with your direct testimony? 15

A. Yes, I am. I am sponsoring Exhibit A-3 (TLK-1), Schedule C32, which is the 16

Regulated AIA. I am also sponsoring Exhibit A-3 (TLK-1), Schedule C33, which 17

describes the various assets owned by IBS, and the allocation methods used to 18

allocate the costs associated with these assets. 19

20



23

Q. Has the Regulated AIA between IBS and its regulated utility affiliates been the 24

subject of a proceeding before the MPSC previously? 25

A. Yes, it has. The Regulated AIA between IBS and its regulated utility affiliates was 26

submitted to the Michigan Public Service Commission (“MPSC” or the “Commission”) 27

in connection with MGUC, Wisconsin Public Service Corporation (“WPS Corp”) and 28

4

Upper Peninsula Power Company (“UPPCO”) seeking waivers from the 1

Commission’s Code of Conduct and Affiliate Transaction Guidelines in Case No. U-2

15325. The Regulated AIA was also included in MGUC’s last general rate case - 3

MPSC Case No. U-15990. 4

5

Q. Have there been any changes to the Regulated AIA since MGUC’s last general 6

rate case proceeding? 7

A. Yes, there has. The only changes are on Exhibits “B” and “C” of the Regulated AIA. 8

These changes were previously filed with the MPSC in the electronic docket for Case 9

No. U-15325. 10

11

Q. Does MGUC seek to recover the forecasted 2014 test year costs allocated to it 12

under the Regulated AIA? 13

A. Yes, it does. The MGUC 2014 revenue requirement includes the amounts incurred 14

in 2012 inflated to 2014, and adjusted for Known and Measurable changes. This 15

resulting amount was included in the 2014 test year for the services to be provided to 16

MGUC by IBS, including the costs that are directly assigned, costs that are assigned 17

using cost-causal allocators, and costs that are assigned using the 18

General/Corporate allocator. The 2014 revenue requirement is explained by Ms. 19

Katherine A. De Cramer in her pre-filed direct testimony. 20

21

Q. Please describe the philosophy and goals underlying the operation of IBS. 22

A. IBS strives to be a leading service company provider of innovative and cost-effective 23

support services and solutions to its affiliates. IBS focuses on the following four 24

areas: 25

1. Customer Focus: Maintaining and demonstrating an in-depth understanding 26 of Integrys’ businesses, developing and delivering innovative, high-value 27

5

services that address business issues and assisting the businesses in 1 achieving their goals; 2

3 2. Service Delivery: Delivering high-quality and cost-effective services in a 4

timely manner; proactively developing, in partnership with its business 5 partners, new and innovative services and solutions that address business 6 needs, leveraging technology and process excellence across its various 7 service categories; 8

9 3. Cost Management and Value Creation: Continually seeking ways to improve 10

processes and reduce costs, opportunities to invest in people, processes and 11 technology that result in meaningful value creation for our business partners 12 and stakeholders; and 13

14 4. Employee Engagement: Maintaining a high-performance culture and staff 15

that exhibit strong technical skills, an in-depth knowledge of the business, 16 and a business mindset. 17

18

Integrys operates six regulated utilities across four states, and has a number of non-19

regulated subsidiaries. As a centralized service company, IBS strives to achieve 20

economies of scale by leveraging employees and management across many 21

affiliates and businesses. Such leveraging reduces the holding company’s system-22

wide costs, and allows those costs to be shared among a larger number of affiliates. 23

24

Q. Please briefly describe the various services provided by IBS. 25

A. The services IBS provides pursuant to the Regulated AIA are described in Exhibit A-26

3 (TLK-1), Schedule C32, pages 18 to 21. Below I show the various IBS functions 27

along with examples of the Administrative & General (“A&G”) services offered by 28

each departmental unit: 29

• Administrative -- Facility services, security services, work space 30 management services and printing services. 31

32 • Environmental -- Environmental planning, permitting, licensing, 33

compliance services, waste management and emergency response. 34 35 • CFO Services -- Accounting, treasury, tax, internal audit and related 36

financial services. 37 38 • Human Resources -- Payroll processing, benefit administration, 39

employee training and development, employee communications, labor 40

6

relations, and recruiting and staffing. 1 2 • Information Technology – Computer operations, software 3

development and maintenance, network support, end-user support, 4 database administration, information systems security, desktop, 5 website, project, infrastructure and telephony services. 6

7 • Project Services -- Project management and support, business case 8

development, competitive excellence concept development, portfolio 9 management and dam safety program management 10

11 • Legal Services -- General legal services, insurance, claims, 12

corporate records, and compliance services. 13 14 • Supply Chain -- Sourcing, fleet and materials management services. 15 16 • Utility Services -- Engineering services, planning and operation of 17

gas distribution systems, performing operational reviews of completed 18 construction, maintenance work of gas distribution lines and operating 19 meter shops, gas competitive excellences stewardship support and 20 project management for gas distribution projects, gas supply (A&G 21 and ministerial) services, and utility customer relations services such 22 as meter reading, billing, credit, collections, call center operations, 23 customer relations, revenue assurance, account management, market 24 research, and customer strategy. 25

26 • External Affairs -- Government and public relations, analysis and 27

formulation of company-wide policies and objectives, rate case 28 management, preparation and dissemination of information for 29 employees, customers, government officials, media and the public. 30

31 • Corporate Functions -- Executive management and oversight, 32

corporate secretary services, corporate-level human resources 33 services, corporate-level business development services. 34

35

Q. Please describe the Regulated AIA, under which IBS provides “shared” or 36

“inter-company” services to the utility operating companies within the Integrys 37

holding company system. 38

A. Under the Regulated AIA, Exhibit A-3 (TLK-1), Schedule C32, IBS provides the 39

services listed above to Integrys’ state-regulated utilities. Generally these services 40

comprise common A&G business activities that each affiliate would need to provide 41

internally or procure in order to operate its business. IBS may also provide additional 42

services that the regulated affiliate may request, provided that the services can be 43

7

provided in a cost-effective manner consistent with applicable law. 1

2

IBS recovers all of its costs of providing these services by direct billing the regulated 3

affiliate whenever practicable. Where direct billing is not practicable, IBS bills 4

affiliates pursuant to the cost allocation factors set forth in Exhibit A-3 (TLK-1), 5

Schedule C32, pages 22 to 27. Services are provided at cost, including direct and 6

indirect labor, overheads, and other cost loaders. The cost of maintaining assets, 7

the associated depreciation, and a return on the net assets are based on the factors 8

identified in Exhibit A-3 (TLK-1), Schedule C33. The Allocation Factors described in 9

pages 22 to 27 of Exhibit A-3 (TLK-1), Schedule C32, are designed to match the 10

costs of the services performed with the entity or entities for which the services are 11

performed. The basic premise underlying the allocation methodology and factors is 12

to regularly zero-out the allocated IBS costs of each “home center” (a departmental 13

or operational unit of IBS). 14

15

Q. Does IBS provide services to its non-regulated affiliates? 16

A. Yes, it does, pursuant to a separate, Non-Regulated AIA that is substantially similar 17

to the Regulated AIA. As explained below, the Gas Supply group within IBS 18

provides services only to the regulated operating companies. The Gas Supply 19

Group’s operations, as required by law, are kept separated from the non-regulated 20

business of Integrys Energy Services, Inc. (“Integrys Energy”) and its subsidiaries. 21

22

Q. Are the parties to the Non-Regulated AIA charged “at cost” for services 23

rendered, as are the parties to the Regulated AIA? 24

A. Yes, they are. The Allocation Factors relevant to the provision of services by IBS are 25

the same under both AIAs. IBS provides all of its services “at cost” -- which is 26

8

required under Federal Energy Regulatory Commission (“FERC”) rules of all 1

centralized service companies, and which IBS must regularly demonstrate as part of 2

its annual cost study or study-update work. Therefore, IBS’s billings to non-regulated 3

affiliates are based on either direct or allocated cost, just like its billings to regulated 4

affiliates. The Allocation Factors are the same under both AIAs. The regulated 5

affiliates of Integrys cannot subsidize their non-regulated affiliates. IBS developed 6

the Allocation Factors to ensure that all costs incurred by IBS are recovered from the 7

entity or entities who originated such costs, and in proportion to their share of the 8

whole. 9

10

Q. The services IBS provides pursuant to the Regulated AIA appear to be typical 11

A&G functions, except for some that are described above as “Utility Services.” 12

Why are these Utility Services provided by IBS? 13

A. The IBS Utility Services unit provides the administrative oversight of the utility 14

engineering, gas supply and certain customer relations functions to Integrys’ 15

regulated utilities. These services are not provided to Integrys’ non-regulated 16

subsidiaries. Thus, for example, the non-regulated subsidiaries have no access to 17

utility customer information through IBS’ provision of customer relations services. 18

The IBS Gas Supply area does not own any gas storage assets or gas supply or 19

pipeline transportation contracts -- these contracts and assets continue to be owned 20

separately by the utility that contracted for those services or that owns the storage 21

assets. Each operating company selects and maintains its own separate portfolio. 22

Each operating company has an IBS-employed manager or director over its gas 23

supply portfolio. IBS does, however, manage these various commodity and capacity 24

contracts. Combining these functions into a single entity provides for more cost 25

effective and consistent processes across the companies. 26

9

1

Q. Please describe the process IBS follows when it directly bills its costs to an 2

affiliate. 3

A. Direct billing involves a full, 100% assignment of the costs associated with a specific 4

service to the customer receiving the service. These costs include overhead 5

charges to reflect the complete cost of providing the service. An example of this 6

would be direct labor charges for an IBS engineer who is assigned to a specific 7

project for one of the affiliates. The costs associated with the engineer’s service 8

would be directly charged and billed to that affiliate for each month that the service 9

was being provided. 10

11

Q. Please describe the process IBS follows when it cannot directly bill its costs to 12

an affiliate. 13

A. In cases where direct charging is not appropriate or practical, costs are allocated 14

using cost-causation principles linked to the relationship of that type of service. This 15

allocation methodology reflects operational aspects of the charge and applies costs 16

in a meaningful and impartial way that allocates costs to the entities for which a given 17

service is provided. The remaining allocations are broad based, using the 18

General/Corporate Allocation Factor that I describe later in my testimony. The 19

primary focus of IBS’s cost allocation methodology is to direct charge as many costs 20

as reasonably possible. 21

22

Q. Can you give examples of each type of allocation? 23

A. Yes, and I will do so by describing three typical services that IBS provides. The first 24

service is provided by the Property Accounting home center. Much of the activity in 25

this home center is project-specific and is allocated through direct billing. However, 26

10

certain activities, such as processing the automated depreciation calculation each 1

month, benefit all companies. Therefore time spent on that activity is recorded in a 2

general departmental activity “cost pool” that is allocated based on each company’s 3

Property Plant & Equipment (“PP&E”) balances. 4

5

Most of the costs for services provided by the Accounts Payable home center are 6

allocated through a cost-causal factor: the number of invoices processed. Although 7

invoice processors could track their time based on the owner of each invoice, that 8

approach is not practical because the costs of doing so would be disproportionate to 9

the billing precision that would be obtained. Instead, the time spent on invoice 10

processing generally is recorded in the general departmental activity “cost pool” and 11

allocated based on each affiliate’s number of invoices. If an employee of Accounts 12

Payable works on a significant separate project for one or more affiliates, that time is 13

tracked and billed directly to the project, and those costs are direct billed and 14

excluded from the total bucket of costs allocated through the cost-causal factor. 15

16

Finally, the cost of Investor Relations activity is allocated via the General/Corporate 17

Allocator. The activities performed by this home center benefit all companies. 18

19

Q. Are additional costs loaded into the labor allocations? 20

A. Yes. With all services, the labor billed to affiliates, whether direct or allocated, 21

includes a labor loading. There are three labor-related loaders. The first is a 22

benefits loader and includes costs for pension, health coverage, life insurance, 23

vacation, disability, payroll taxes and other similar or related costs. The second 24

loader is designed to capture the cost of providing work space for the employees 25

performing the service. These costs include lease costs or operating costs if the 26

11

space is owned, depreciation and return on the building or leasehold improvements, 1

depreciation and return on furniture, PCs, common printers/copiers, etc. If another 2

entity is sharing this space with IBS, then an adjustment for billing to that entity would 3

take place prior to calculating a work space overhead. The third is a Pay-at-Risk 4

loader which captures the costs of the Pay-at-Risk compensation for the IBS non-5

union employees. This Pay-at-Risk compensation allows regular employees 6

performing services to maintain pay and benefits that are competitive at the median 7

of the market, as further described in the pre-filed direct testimony of Noreen E. 8

Cleary. 9

10

Q. How are labor costs and related loaders tracked? 11

A. When the affiliates are billed, labor costs are “loaded” to calculate the average cost 12

per hour actually worked by any given employee. All personnel who “bill” any time to 13

affiliates as a provider of services on behalf of IBS accurately report that time in 14

order to reflect actual hours worked on each service provided by or on behalf of IBS 15

separately from all other, non-IBS projects for their primary employer. 16

17

Our ultimate goal, which is a FERC requirement for centralized service companies, is 18

to be as transparent as possible in accurately reflecting all costs reasonably incurred 19

by or on behalf of IBS in its provision of services to its customers. This is particularly 20

true with respect to labor costs, which comprise a significant portion of IBS’s monthly 21

expenses. 22

23

Q. What other costs are allocated to affiliates? 24

A. In addition to labor and contract labor costs, each home center incurs general costs 25

related to running a department. This includes office supplies, administrative time 26

12

and training, among other costs. These costs are allocated to the affiliates in the 1

same proportion as the direct and cost-causal labor charged to them – that is, the 2

costs are accumulated at the higher-level functional categories, and then allocated 3

based on the percentage of labor billings to each of the affiliates at each of the high 4

levels. By doing this, these “general costs” are charged to the affiliates in a cost-5

causal manner. 6

7

In addition to general use office space and equipment, other assets including 8

systems and special use assets (e.g., print shop assets) are owned and used by IBS 9

to provide services to its affiliates. Depreciation and a return on assets, along with 10

the cost to maintain these assets, are allocated based on appropriate factors as 11

indicated on Exhibit A-3 (TLK-1), Schedule C33. 12

13

Each operational level home center also needs to perform services for other home 14

centers within IBS. The cost of that activity is charged to an IBS entity level home 15

center. The total cost charged to this home center is then allocated each month to 16

each affiliate based on the ratio of all other labor charges to each affiliate as 17

compared to the whole of such labor charges. This allocation happens after the 18

other home centers have billed but before the final billing is calculated, as described 19

below. In this manner, IBS’s own internal “cost of doing business” is allocated and 20

charged to the affiliates in a cost-causal manner – in proportion to all other labor 21

billings by IBS to each of its affiliates in a given billing period. 22

23

In addition to the above costs, a return on working capital is allocated to all affiliates 24

based on the asset category as indicated on Exhibit A-3 (TLK-1) Schedule C33, with 25

a pre-tax weighted cost of capital from the most recent rate order for each utility 26

13

applied to that allocation. 1

2

Differences between actual overhead costs incurred and overhead costs billed, are 3

allocated to affiliates each month based on the ratio of all other charges to each 4

affiliate as compared to the whole of such charges. 5

6

Home centers within IBS may also procure products and services for the benefit of 7

individual affiliates, and in such cases the associated costs are billed directly to the 8

affiliates. Contracted labor and professional services procured to assist a home 9

center in providing services are billed based on work performed, similar to internal 10

labor allocations but excluding labor overhead. 11

12

Q. Please describe the General/Corporate Allocator. 13

A. The General/Corporate Allocator is used for the allocation of costs across the 14

Integrys holding company system in cases where a service provides system-wide 15

benefits, or in any event where the cost is driven by the holding company system as 16

a whole rather than any particular entity. 17

18

Q. What cost factors go into the calculation of the General/Corporate Allocator? 19

A. There are two factors that are calculated for each entity within the Integrys holding 20

company system (including IBS): 21

1. Total assets, and 22 23 2. Total non-fuel operations and maintenance (“O&M”) costs. 24

25

For each factor a percentage is calculated to determine the individual company’s 26

portion of the total dollars in that factor. The average of these two percentages for 27

an entity is that entity’s allocation percentage, or factor, for the General/Corporate 28

14

Allocation Factor. 1

2

For both the Cost Causal Allocation Factors and the General/Corporate Allocator, a 3

“percentage of the whole” determination is used, such that the percentage charged 4

to an entity is based on that entity’s units in the numerator, and the denominator is 5

the sum total of such units for all entities within the holding company system who 6

take the particular service for which the Allocation Factor is being utilized. 7

8

Q. In calculating the total assets, how do you account for derivative assets, 9

goodwill and other “non-ordinary” assets? 10

A. These types of assets are excluded from the total asset amounts for the purpose of 11

calculating the General/Corporate Allocator. In the case of derivative assets, 12

accounting rules require the valuation of these contracts for each reporting period 13

prior to actual settlement of the contract. As commodity prices change, the value of 14

these assets will also change with no real change in the relative value of each 15

affiliate to the other affiliates. In the same way, certain companies may have booked 16

goodwill due to the fact that they were acquired by Integrys. Other companies may 17

have a similar but unrecorded intrinsic value, therefore such items are excluded in 18

order to result in a more appropriate cost allocation. 19

20

Q. Please describe the costs that are included in the Non-Fuel O&M calculation. 21

A. All O&M costs (whether regulated or non-regulated) are included in this category. 22

Examples of such costs include O&M labor, materials, and outsides services. As 23

noted earlier, fuel, cost of goods sold, purchased power and similar costs are not 24

included in these allocation calculations. Additionally, marked-to-market gains or 25

losses recorded in O&M, if any, are excluded. 26

15

1

Q. Why does Integrys believe this methodology is appropriate for the 2

General/Corporate Allocation Factor? 3

A. There is no “right answer” that works for every holding company system. Instead, 4

the appropriate general allocator depends on the unique facts and circumstances of 5

each holding company system. This is confirmed by FERC’s Uniform System of 6

Accounts (“USOA”) (18 CFR § 367.28) for centralized service companies, which 7

requires IBS to create a cost accumulation system and identify methods of allocation, 8

but does not prescribe any specific allocation methodology. 9

10

The two allocation factors that IBS chose, total assets and O&M costs, are 11

considered proxies for the relative size of each affiliate as well as the activities that 12

support each affiliate. While the corporate oversight and compliance required for any 13

individual entity has both fixed and variable aspects, a large asset base can add 14

specific risk and oversight needs as well as access to capital markets. Likewise, the 15

overall costs to run a business (O&M) requires differing degrees of oversight (e.g., 16

larger and more complex contracts, more employees, etc.). Integrys believes that 17

total assets and O&M costs provide a fair allocation of costs when using the 18

General/Corporate Allocator. 19

20

Q. How regularly are the various allocation inputs and factors re-calculated? 21

A. The allocation inputs and factors that will be used in any calendar year are calculated 22

during the preparation of the annual budget for that year. Most of these inputs and 23

factors are based on the most recent month-end balance or last twelve full months of 24

activity, as appropriate. Labor overhead rates, however, are based on projections of 25

labor and overhead costs in the budgeted calendar year. 26

16

1

The factors and inputs are modified during the calendar year only if significant 2

changes in actual or anticipated activity were to occur. 3

4

Q. How does IBS allocate costs for services that it performs for Integrys itself 5

(e.g., services related to the fact that it is a publicly-traded entity)? 6

A. For the sake of efficiency these costs are allocated by IBS to the affiliates (including 7

Integrys itself) because the functions benefit all affiliates. Another option would be to 8

first charge such costs to Integrys and then have Integrys bill its various subsidiaries, 9

but this would not be consistent with our centralized service company approach, nor 10

with the fact that we have structured our shared services organization such that 11

Integrys officers and personnel are IBS employees. Also, if we did this, Integrys 12

would use the same allocation factors and methodologies used by IBS to recover all 13

allocable costs from its subsidiaries, so the result would be to add a series of 14

unnecessary and duplicative steps to the process with no difference in the ultimate 15

results. 16

17

Integrys is allocated a portion of all other relevant and applicable costs that are 18

allocated via the appropriate Allocation Factor (including the General/Corporate 19

Allocator for many services), and such allocated costs are also charged to and 20

remain at the holding company level. Any costs that are not allocable by Integrys to 21

its subsidiaries (for example, most business development costs) are charged to and 22

remain at the holding company level. 23

24

Q. You indicated that IBS is allocated certain costs as part of the 25

General/Corporate Allocator. Are those costs then re-allocated by IBS to the 26

17

affiliates, so that it can “zero-out” all of its costs? 1

A. Yes, IBS recovers, from its affiliates, the costs allocated to it under any Allocation 2

Formula. This occurs as part of the final calculation of the various percentages 3

(adding up to 100% in every case) that I described earlier. 4

5

This is appropriate because IBS was formed to provide, at cost, cost-effective inter-6

company services. IBS allows Integrys customers to optimize the level of net 7

savings and benefits that result from a centralized service company. Therefore, it is 8

appropriate for IBS to recover its reasonably incurred costs from the affiliates. 9

10

Q. Please describe the federal regulation of IBS. 11

A. IBS is a “centralized service company” subject to FERC regulation and regulatory 12

requirements, including the Uniform Systems of Accounts (“USOA”) promulgated by 13

FERC for such entities. This exhaustive USOA, modeled after that used by utilities, 14

is found in 18 CFR Part 367. IBS must also follow the detailed record retention 15

requirements promulgated by FERC at 18 CFR Part 368. Finally, IBS must file a 16

detailed annual report with FERC, the FERC Form No. 60 (18 CFR Part 369), the 17

annual report required of all centralized service companies containing financial 18

reporting tied to USOA accounts as well as reporting various other matters and 19

transactions. FERC also has broadly defined access to the books and records of 20

holding companies and subsidiaries under 18 CFR Part 366. 21

22

Q. Is the cost of service rendered by IBS equal to or less than if MGUC performed 23

the same services on a stand-alone basis? 24

A. Yes, it is. The services provided by IBS represent activity that any company would 25

need to perform to function as a separate company. IBS generates savings for 26

18

MGUC and its customers because of the efficiencies and synergies it brings in 1

providing services to Integrys which are passed along to MGUC on a pro rata basis. 2

With IBS providing the same services to the complete Integrys family, the costs of 3

these activities can be shared among all of the companies. Although some costs are 4

variable to the size of the company, many of these costs are fixed and therefore a 5

smaller company would pay a higher amount in proportion to their relative size if the 6

service was provided by an outside party or fully staffed at the company to perform 7

the functions. MGUC could not self-provide the same overall package of services 8

provided by IBS at a lower cost. 9

10

Q. Is the arrangement between IBS and MGUC a benefit to MGUC and its 11

customers? 12

A. Yes, it is. In addition to the economies of scale described above, MGUC also 13

receives the benefit of access to in-house experts who can be retained only in larger 14

companies. For example, many of the same requirements that one utility may face 15

from an environmental compliance perspective will impact other companies within 16

the Integrys family. Having one group provide the support and research needed not 17

only lowers the costs, but helps to ensure strong compliance programs with broad 18

institutional knowledge. 19

20

Q. Based on the IBS cost allocation procedures described in your testimony and 21

documented in the Regulated AIA, are the IBS costs reasonably and equitably 22

allocated among the IBS affiliated companies? 23

A. Yes, they are. The Regulated AIA to which MGUC is a party with IBS accurately and 24

transparently assigns and allocates IBS costs to MGUC and among the other IBS 25

affiliated companies, and provides reasonable assurance to the Commission that 26

19

costs related to MGUC operations are fairly and accurately determined. 1

2


A. Yes, it does. 4

MASTER REGULATED AFFILIATED INTEREST AGREEMENT

THIS MASTER REGULATED AFFILIATED INTEREST AGREEMENT

(“Agreement”) is entered into this ____ day of ____________, 2007, by and among Integrys

Business Support, LLC, a Delaware limited liability company (“Integrys Support”) and all of the

regulated subsidiaries of Integrys Energy Group, Inc. (“Integrys”) as listed and defined on

Exhibit A. All of the parties to this Agreement shall be collectively referred to as “Parties,” and

all of the Parties other than Integrys Support shall be collectively referred to as the “Client

Companies.”

RECITALS

A. Each of the Client Companies is a state-regulated utility operating company, a

wholly-owned subsidiary of Integrys, and an affiliated interest of the other Parties pursuant to

the applicable public utility law of Wisconsin, Michigan, Minnesota, and Illinois.

B. In order to maximize efficiencies and economies of scale, the Parties desire to

plan and operate their regulated utility businesses with the integration of certain activities by

receiving services, employees, properties, information systems, property, services and/or

anything else of commercial value from a single centralized service company provider.

C. Integrys Support and the Client Companies desire to enter into this Agreement

whereby Integrys Support agrees to provide, and the Client Companies agree to accept and pay

for, various services as described herein, with such payments by the Client Companies being at

the fairly and equitably allocated costs as also provided herein.

D. From time to time Integrys Support will perform various services for or on behalf

of the Client Companies, and further Integrys Support will make its property, employees and

other things of value available to or for use by the Client Companies, all of which transactions

are affiliated interest arrangements subject to the regulatory jurisdiction of the Public Service

Commission of Wisconsin (“PSCW”), Michigan Public Service Commission (“MPSC”),

Minnesota Public Utilities Commission (“MPUC”), and Illinois Commerce Commission (“ICC”)

Case No. U-17273 Witness: Tracy L. Kupsh

Exhibit A-3 (TLK-1) Schedule C32

Page 1 of 27

(collectively the “Commissions”) pursuant to applicable Wisconsin, Michigan, Minnesota, and

Illinois law.

NOW, THEREFORE, the Parties agree as follows:

AGREEMENT

Integrys Support and the Client Companies, in consideration of the mutual promises

made in this Agreement, agree as follows:

1.0 Provision of Services by Integrys Support

1.1 The term “services” as used in this Agreement shall include management,

supervisory, construction, engineering, accounting, legal, financial, human

resources, information services, customer service, accounting, billing, operations

and other administrative and general services, including without limitation the

provision of any service or any other arrangement which among affiliates may

require approvals, waivers or other authorizations under the applicable utility law

of the states of Wisconsin, Michigan, Minnesota and/or Illinois.

1.2 Except as otherwise provided herein or required under applicable law, Integrys

Support shall furnish to each Client Company services in those categories listed

and described in Exhibit B. Integrys Support shall also furnish to each Client

Company services in addition to those listed and described in Exhibit B, as may

be requested by each such Client Company from time to time, provided that

Integrys Support is reasonably able and willing to perform or provide such

services, and further provided that if an additional category of services is

requested by one or more Client Companies and is provided by Integrys Support

hereunder, the Parties shall comply with the requirements of Section 7.3. In

connection with its provision of services hereunder, Integrys Support may also

from time to time provide or furnish property, assets, rights, interests, or other

items of commercial value.



Page 2 of 27

1.3 Integrys Support shall furnish to the Client Companies the services described in

Section 1.2 in such manner as the Client Companies reasonably require from

time to time, unless Integrys Support is not reasonably able to perform or provide

such services or is unable to do so in a manner consistent with applicable law.

1.4 Notwithstanding any other provision of this Agreement, a Client Company shall,

upon at least one hundred twenty (120) days prior written notice, have the right to

purchase the services described in Section 1.2 from a service provider other than

Integrys Support if: (i) such third party service provider offers comparable

services, (ii) the Client Company presents comparable internal and external

costing and service data to demonstrate to Integrys Support that the third party

services would be provided at a lower all-in price than the all-in price charged by

Integrys Support for such services, and (iii) the Client Company presents

comparable internal and external costing and service data to demonstrate to

Integrys Support that provision of the services by a third party service provider

will be of overall benefit to the Integrys holding company system. With respect to

any such showing by a Client Company, all relevant information that is provided

by any Client Company to Integrys Support shall be copied to all of the other

Client Companies.

1.5 In the event that any Client Company appropriately refuses to take or accept any

services from Integrys Support pursuant to Section 1.4, such refusal shall not

otherwise affect any other right, duty or obligation of any Party hereunder.

1.6 The services described herein shall be directly assigned or allocated by activity,

project, program, work order or other appropriate manner on a case-by-case

basis. Each Client Company may establish and document with Integrys Support

its expectations and requirements with respect to any particular service to be

rendered hereunder, including the establishment of targeted service and



Page 3 of 27

performance levels and measures to determine whether such service level

indicators are being achieved. A Client Company shall have the right from time

to time to modify any activity, project, program or work order provided that (i) any

such modification that results in a material change in the scope of the services to

be performed or equipment to be provided is acceptable to Integrys Support, (ii)

the cost for the services covered by the activity, project, program or work order

shall include any expense incurred by Integrys Support as a direct result of such

modification of the activity, project, program or work order, and (iii) no

modification of an activity, project, program or work order shall release a Client

Company from liability for payment of all direct or allocable costs already incurred

by or contracted for by Integrys Support pursuant to the activity, project, program

or work order, regardless of whether the services associated with such costs

have been completed prior to such modification taking effect.

2.0 Determination of Costs for Services.

2.1 All services provided by Integrys Support shall be at cost, as hereinafter defined.

It is the intent of the Parties that the payment for services rendered by Integrys

Support to the Client Companies hereunder shall cover all of Integrys Support’s

costs of doing business (less the cost of services provided to affiliates not a party

to this Agreement and to non-affiliated companies, and credits for miscellaneous

income items), including, but not limited to, salaries and wages, office supplies

and expenses, outside services employed, property insurance, injuries and

damages, employee pensions and benefits, miscellaneous general expenses,

rents, maintenance of structures and equipment, depreciation and amortization,

payroll and other taxes, and compensation for use of capital (with a return on

Integrys Support’s net assets charged to each Client Company at a rate equal to

the prevailing pre-tax weighted cost of capital (economic cost of capital)



Page 4 of 27

authorized by the Commission having jurisdiction over the rates of that Client

Company).

2.2 As compensation to Integrys Support for the services rendered hereunder, each

Client Company shall pay to Integrys Support all costs which are reasonably

related to the services performed by Integrys Support for or on behalf of such

Client Company. Integrys Support shall maintain a detailed cost accumulation

and classification system, and shall allocate costs to each Client Company

pursuant to the following methodology: (i) to the extent possible and prior to

allocating costs pursuant to subsections (ii) and (iii) of this Section 2.2, costs

associated with a service that is specifically performed for a single Client

Company will be directly assigned and billed to that Client Company; all costs

directly assigned and billed to any entity taking service from Integrys Support

shall be deducted from the amount being allocated in subsections (ii) and (iii) of

this Section 2.2; (ii) where more than one Client Company receives benefits from

a service, such amounts shall be allocated among such Client Companies (and

any other affiliates within the Integrys holding company system to whom the

service is rendered by Integrys Support) pursuant to the applicable cost

Allocation Factor(s) set forth in Exhibit C; and (iii) where a service provided by

Integrys Support is of a general nature applicable to all Client Companies, costs

incurred by Integrys Support with respect to such service shall be allocated

among the Client Companies (and any other affiliates within the Integrys holding

company system to whom applicable services are rendered by Integrys Support)

pursuant to the applicable cost Allocation Factor set forth in Exhibit C.

2.3 The Allocation Factors set forth in Exhibit C shall be subject to periodic review by

Integrys Support in connection with the studies required by Section 4.3, and may

be reviewed more frequently if deemed appropriate by Integrys Support.



Page 5 of 27

2.4 The method of assignment or allocation of costs contemplated herein and in

Exhibit C and/or the Allocation Factor or Factors assigned to any category of

service in Exhibit B, may be modified or changed by Integrys Support, without

amendment of this Agreement other than insertion of appropriate replacement

Exhibits, provided that (i) all services rendered hereunder shall be at actual cost

thereof, (ii) such costs are fairly and equitably assigned or allocated in a manner

consistent with Section 2.2, and (iii) the Parties comply with the requirements of

Section 7.3.

2.5 With respect to any charges imposed by Integrys Support for services provided

under this Agreement that are subject to the jurisdiction of the FERC, no Party

shall elect, or cause any affiliate to elect on their behalf, to have the FERC review

pursuant to Section 1275 of the Energy Policy Act of 2005, 42 U.S.C. § 16462,

the allocation of costs for goods and services provided by Integrys Support until

the Commissions with jurisdiction to do so have reviewed and taken required

actions regarding the affiliated interest transactions and agreements, or

amendments thereto, associated with Integrys Support. If the Commissions have

not completed review and approval or taken other appropriate action within a

reasonable time, then any Party or its affiliate may seek such FERC review after

giving the Commissions who have not so acted at least 60 days’ prior written

notice.

3.0 Billing; Payment; Related Provisions.

3.1 Integrys Support shall render a monthly bill to each Client Company reflecting the

charges for services and property provided in the preceding month. Each bill

shall include sufficient information and in sufficient detail to permit each Client

Company to identify and classify the charge in terms of the system of accounts

prescribed by the regulatory authorities to which it is subject.



Page 6 of 27

3.2 Upon receipt of a monthly bill for services rendered by Integrys Support

hereunder, each Client Company shall promptly pay any undisputed portion of

the bill within ten (10) business days.

3.3 If a Client Company disputes the calculation of any portion of a monthly bill it

shall, when it pays the undisputed portion as contemplated by Section 3.2 or in

any event no later than sixty (60) days after receiving the bill, inform Integrys

Support in writing as to its reasons for its dispute. Integrys Support and the

Client Company shall then meet to resolve in good faith the dispute, and shall

involve the other Client Companies in the resolution of the dispute to the extent

necessary and appropriate.

4.0 Accounting and Recordkeeping; Annual FERC Reports; Cost Studies; Annual Client and

Integrys Support Company Reports; Internal Audit.

4.1 All accounts and records of Integrys Support shall be kept in accordance with the

relevant requirements promulgated by the FERC from time to time, including

without limitation Parts 367 and 368 of the FERC’s regulations. Without limiting

the foregoing, Integrys Support shall maintain adequate books and records with

respect to all of its transactions hereunder, and shall record the costs to be

allocated to the Client Companies in appropriate accounts in its general ledger

system. Integrys Support shall be responsible for maintaining internal controls to

ensure the costs associated with all transactions hereunder are properly and

consistently allocated and billed in accordance with the terms and provisions of

this Agreement.

4.2 Integrys Support shall provide the Commissions and the Client Companies a

copy of its FERC Form No. 60, or such other annual report required by the FERC

of centralized service companies from time to time, contemporaneous with its

annual filing of such report with the FERC. Integrys Support shall also file with



Page 7 of 27

the Commissions, contemporaneous with its annual filing of such report with the

FERC, the following schedules. These schedules shall list all costs incurred by

Integrys Support and all costs allocated to all entities to whom Integrys Support

provides or provided services. In Illinois, these schedules shall be filed as

supplemental schedules to Form 21.

a) A schedule summarizing the direct and indirect charges for each functional area in Exhibit B. The report shall present the dollar amounts and percentages charged to each party to this Agreement as listed in Exhibit A, as well as to all other entities that receive direct or indirect charges from Integrys Support for such functional areas.

b) A schedule providing a breakdown by subaccount of Account 923, Outside Services Employed. The schedule shall aggregate amounts paid to any one payee in each subaccount. If one subaccount is less than $100,000, only the aggregate number and amount of all such payments included within the subaccount shall be shown. The schedule shall include subtotals for each type of service.

c) A schedule providing a listing of each pension and benefit program provided by Integrys Support. Such listing shall be limited to amounts over $100,000.

d) A schedule providing a listing of the amount included in Account 930.1, General Advertising Expenses, classifying the items according to the nature of the advertising and as defined in the account definition. If a particular class includes an amount in excess of $100,000 applicable to a single payee, show separately the name of the payee and the aggregate amount applicable thereto.

e) A schedule providing a listing of the amount included in Account 931, Rents, classifying such expenses by major groupings of property, as defined in the account definition of the Uniform System of Accounts in Part 367 of the FERC’s regulations.

f) A schedule providing an analysis of Account 408, Taxes Other Than Income. The report shall separate the analysis into two groups (1) other than U.S. Government taxes and (2) U.S. Government taxes. The report shall specify each of the various kinds of taxes and show the accounts thereof. A subtotal shall be provided for each class of tax.

g) A schedule providing a listing of the amount included in Account 426.1, Donations, classifying such expense by its purpose. The aggregate number and amount of all items of less than $100,000 may be shown in lieu of details.

h) A schedule providing a listing of the amount included in Account 426.5, Other Deductions, classifying such expenses according to their nature.



Page 8 of 27

4.3 At least once every three years, Integrys Support shall conduct a new study of

the cost of services provided hereunder, for the purpose of testing compliance

with the Agreement and to analyze the market price of services provided. The

study shall be updated at least annually. Integrys Support shall provide each

Client Company with a copy of each new study or update, as the case may be,

no later than May 1 of the year following the end of the most recently completed

fiscal year covered by the new study or update. The first such new study shall

pertain to the period ending December 31, 2008, and shall be due on or before

May 1, 2009.

4.4 Each year there shall be an internal audit of Integrys Support’s transactions

involving each of the Client Companies for the purpose of testing compliance

with the Agreement. In addition, the audit will include a review of transactions

involving other entities to whom Integrys Support provides service as well as the

verification that all direct billings to regulated and non-regulated affiliates as well

as unaffiliated parties, if applicable, were properly deducted prior to the

allocations being calculated. The Client Companies shall submit a copy of the

audit report to the person or department designated by the Commissions or the

Commissions’ staffs no later than July 1 of each year. In Illinois, the report shall

be submitted to the ICC’s Manager of the Accounting Department or any

successor. The first such audit report shall pertain to the period ending

December 31, 2008, and shall be due on or before July 1, 2009.

4.5 Each year by May 1, the Client Companies shall file with their respective

Commissions, and submit a copy to the person or department designated by the

Commissions or the Commissions’ staffs, billing reports showing monthly

charges by Integrys Support to each of the Client Companies. These reports

shall show all costs incurred by Integrys Support and all costs allocated to all



Page 9 of 27

entities to whom Integrys Support provides services. In Illinois, the report shall

be submitted to the ICC’s Manager of the Accounting Department or any

successor.

5.0 Representations and Warranties of the Parties.

5.1 Each Party has the right, power, and authority to enter into and perform its

obligations under this Agreement.

5.2 Each Party has taken all requisite corporate action to approve execution,

delivery, and performance of this Agreement, and this Agreement constitutes a

legal, valid and binding obligation of each Party enforceable in accordance with

its terms.

5.3 The fulfillment of obligations hereunder will not constitute a material violation of

any existing applicable law, rule, regulation, or order of any governmental

authority. The Parties acknowledge that all or portions of this Agreement may be

challenged before regulatory agencies or a court of competent jurisdiction by

other persons or entities not Parties hereto. In such event, the Parties agree that

each will use its best efforts before such agencies and courts to support the

pursuit and accomplishment of the Parties’ mutual endeavors hereunder.

6.0 Additional Representations, Warranties and Covenants of Integrys Support.

6.1 In its performance of services hereunder, Integrys Support: (i) shall follow

applicable federal and state regulations, including codes and standards of

conduct, with respect to the sharing of confidential information it receives from

any Client Company with another; (ii) shall not give one or more Client

Companies, or any other affiliate within the Integrys holding company system, a

competitive advantage in relevant markets; and (iii) shall not subsidize any Client

Company and shall not cause any Client Company to subsidize any of its

affiliates.


Exhibit A-3 (TLK-1) Schedule C32 Page 10 of 27

6.2 Integrys Support shall make readily available to each Commission, FERC and/or

any other governmental or regulatory agency with jurisdiction under applicable

law, reasonable access to its books and records (including without limitation the

basis for its computation of cost allocations) as may be necessary for each

Commission or other agency to review Integrys Support’s transactions with each

Client Company within such Commission’s or agency’s jurisdiction. Without

limiting the foregoing, each Commission shall have full access to the books and

records of Integrys Support as contemplated under applicable law, which access

shall be made readily available to each Commission in their respective states.

7.0 Additional Provisions.

7.1 This Agreement shall become effective upon the issuance of approvals or

waivers as might be required by law, from each and all of the Commissions, and

upon execution of the Agreement by all of the Parties. Once effective, this

Agreement shall continue in full force and effect until and unless modified or

terminated as provided herein.

7.2 This Agreement may be amended or modified at any time by mutual agreement

of the Parties in writing. This Agreement, and any rights hereunder, may not be

assigned without the written consent of all Parties hereto. Except as otherwise

provided herein or under applicable law, any such modification, amendment or

assignment shall not become effective until receipt of approvals or waivers by the

Commissions as might be required by law. The addition of a Party to this

Agreement, or the termination of this Agreement as to a Party, shall not require

the prior approval of the Commissions, but in either case Integrys Support shall

provide the Commissions at least sixty (60) days prior written notice of such

event.



7.3 At least sixty (60) days prior to any change to (i) Exhibit A reflecting the current

Parties to this Agreement, (ii) Exhibit B reflecting the services and categories of

service provided by Integrys Support hereunder, and/or (iii) Exhibit C reflecting all

Allocation Factors in use hereunder, Integrys Support shall provide to the Client

Companies, and the Client Companies shall file with the Commissions and, if

appropriate, the FERC, a revised version of such Exhibit(s) to be changed along

with an indication of what change(s) will be made.

7.4 At least sixty (60) days prior to leaving the Integrys holding company system, a

Client Company shall provide written notice to Integrys Support, and Integrys

Support will then copy the other Parties and the Commissions as soon as

practicable upon receipt of any such notice. Any such Client Company may

continue to receive services from Integrys Support for a reasonable transitional

period of time following such departure from the Integrys holding company

system.

7.5 In providing all services, Integrys Support may arrange, where it deems

appropriate, for the services of such third party experts, consultants, attorneys,

advisers, or other contractors or agents with necessary qualifications as may be

required for or pertinent to the performance of services for the Client Companies

hereunder.

7.6 Each Party shall treat in confidence all information that it may obtain from or

regarding the other Parties and their respective businesses during the term of

this Agreement. Each Party agrees to protect the other Parties’ information using

the same degree of care with which they use to protect their own confidential

information, and in no event less than reasonable care. Except to the extent

disclosure of such information is required by a governmental authority having

jurisdiction, such information shall not be communicated to any person other than



the Parties, and shall be shared among the Parties only to the extent certain

persons need to know such information in order for the Parties to perform under

this Agreement. If a Party is required to disclose confidential information to a

governmental authority, such Party shall take reasonable steps to make such

disclosure confidential under the rules of such governmental authority.

Information provided hereunder shall remain the sole property of the Party

providing such information. The requirements of this Section 7.6 shall not apply

with respect to information that (i) is or becomes available to such Party from a

source other than the Party providing such information, unless such other source

has imposed confidentiality restrictions, or (ii) is or becomes available to the

public other than as a result of disclosure by such Party or its agents.

7.7 The Parties agree and acknowledge that any legal advice or legal services

provided, or arranged to be provided, by or on behalf of Integrys Support to one

or more of the Client Companies will be for the direct or indirect benefit or

common interest of all of the Client Companies, and it is therefore the intention of

all Parties hereto to maintain all privileges that may apply to any communications

related to the provision or receipt of such legal advice or services.

7.8 The Client Companies hereby appoint Integrys Support as agent to represent

them in performing services for or on behalf of the Client Companies. The Client

Companies also authorize Integrys Support to purchase (i.e., take title to) various

commodities, goods and assets in connection with its performance of services

hereunder, and to resell (i.e., convey title to) such commodities, goods and

assets to the Client Companies if necessary in the course of performing services

hereunder. Any resale of such commodities, goods and assets by Integrys

Support to the Client Companies, and/or any use of such commodities, goods

and assets by Integrys Support in its provision of services hereunder, shall be at



the costs incurred by Integrys Support, allocated among the Client Companies

pursuant to the methodologies prescribed herein. Integrys Support shall be

accountable for all funds advanced or collected on behalf of a Client Company in

connection with any transaction in respect of which Integrys Support provides

services. The provision of services by Integrys Support hereunder shall in all

cases and notwithstanding anything herein to the contrary be subject to any

limitations contained in authorizations, rules or regulations of those governmental

agencies having jurisdiction over Integrys Support or its provision of services

hereunder.

7.9 In the event that any amendment to this Agreement does not receive any

approval or waiver of approval by all Commissions that may be required from

time to time, then the Parties shall promptly negotiate in good faith new

provisions to restore such amendment, as nearly as possible, to its original intent

and effect, and thereafter file for approval or waiver of approval of the

Commissions.

7.10 If any governmental or regulatory agency or court of competent jurisdiction holds

that any provision of this Agreement is invalid, or otherwise takes action resulting

in the impossibility or impracticability of performance of all or a portion of this

Agreement, the remainder of this Agreement shall not be affected thereby and

shall continue in full force and effect. In the event any provision of this

Agreement is so held invalid, the Parties hereto shall promptly renegotiate in

good faith new provisions to restore this Agreement as nearly as possible to its

original intent and effect.

7.11 No course of dealing or course of performance between the Parties shall be

construed to alter the terms hereof.



7.12 The Parties agree that there is no third party beneficiary of this Agreement and

that the provisions of this Agreement do not impart enforceable rights to anyone

who is not a Party.

7.13 This Agreement shall be governed by and construed in accordance with the laws

of the State of Wisconsin, without regard to principles of conflicts of law;

provided, however, that no Client Company shall be required to comply with this

Agreement to the extent such compliance would be a violation of the public utility

laws of any state in which such Client Company conducts its regulated utility

operations.

7.14 This Agreement may be executed in any number of counterparts, each of which

when executed and delivered shall be deemed to be an original and all of which

counterparts taken together shall constitute but one and the same instrument.



IN WITNESS WHEREOF, each of the Parties hereto has caused this Agreement to be

executed on its behalf by its officers thereunto duly authorized as of the day and year first above

written.

INTEGRYS BUSINESS SUPPORT, LLC WISCONSIN PUBLIC SERVICE CORPORATION

By By

Name Name

Title Title

UPPER PENINSULA POWER COMPANY MICHIGAN GAS UTILITIES CORPORATION

By By

Name Name

Title Title

MINNESOTA ENERGY RESOURCES THE PEOPLES GAS LIGHT AND COKE CORPORATION COMPANY

By By

Name Name

Title Title

NORTH SHORE GAS COMPANY By

Name

Title



Exhibit A

Client Company Parties to the

Master Regulated Affiliated Interest Agreement Michigan Gas Utilities Corporation

a Delaware-incorporated Michigan public utility headquartered in Green Bay, Wisconsin, engaged in the business of providing natural gas service

Minnesota Energy Resources Corporation

a Delaware-incorporated Minnesota public utility headquartered in Green Bay, Wisconsin, engaged in the business of providing natural gas service

North Shore Gas Company

an Illinois public utility corporation headquartered in Chicago, Illinois, engaged in the business of providing natural gas service

The Peoples Gas Light and Coke Company

an Illinois public utility corporation headquartered in Chicago, Illinois, engaged in the business of providing natural gas service

Upper Peninsula Power Company

a Michigan public utility corporation headquartered in Houghton, Michigan, engaged in the business of providing regulated electric service

Wisconsin Public Service Corporation

a Wisconsin public utility corporation headquartered in Green Bay, Wisconsin, engaged in the business of providing regulated electric and natural gas service



Exhibit B – Reg AIA

1. Administrative services

Administrative services represent facility management services for owned and leased facilities, excluding power plants. This includes operations and maintenance of structures, capital improvements, interior space planning, printing services, security and janitorial, acquisition and management of real estate and land rights including easements and right-of-ways.

Allocation Factors – (1) Square Footage; (2) Number of Office Moves; (3) FTE Work Estimate; (4) Number of Employees; (5) Dollars Associated with Number of Imprints; (6) Composite Allocator; (7) Number of Customers.

2. Corporate development

Corporate development refers to strategic planning, merger and acquisition analysis and support, market intelligence, project management, business and quality improvement processes, business development, asset analysis and divestiture, and resource allocation. It also consists of work performed to determine, implement and track corporate performance goals, initiatives and measures.

Allocation Factors – (1) General/Corporate.

3. Corporate secretary

Corporate secretary refers to those services required of a publicly held corporation, including shareholder, board of director and related committee meetings and minutes.


4. Environmental

Environmental refers to the performance of assessments, investigations, remediation and other activities as required to ensure compliance with applicable environmental statutes and regulations, permitting, licensing, due diligence, waste management and emergency response.

Allocation Factors – (1) FTE Work Estimate.

5. Executive management

Executive management services refers to the executive management and oversight activities performed by officers of the company and other senior executives. Such activities involve the formulation of general business plans and policies, selection of key management personnel, and allocation of financial resources.




6. External affairs

External affairs refers to the preparation and dissemination of information to employees, customers, government officials, the public and the media. It also involves administering the company’s activities in the areas of governmental relations, community support and economic development, as well as the analysis and formulation of regulatory policy, rate case preparation and rate administration.

Allocation Factors – (1) Total Property, Plant and Equipment; (2) Number of Employees; (3) General/Corporate; (4) Number of Customers.

7. Financial services

Financial services refers to accounting, finance, treasury, tax, internal audit and relating financial services. Examples of activities performed within these various financial disciplines includes the following: maintain corporate books and records, prepare financial and statistical reports, process payments to vendors, ensure compliance with tax laws and regulations, manage debt and maintain banking relationships, invest pension assets, establish and monitor internal controls, perform financial and risk analysis, prepare budgets and forecasts, maintain shareholder records, and communicate with the investment community. Allocation Factors – (1) Number of Invoices Processed; (2) Number of Transactions; (3) Total Property, Plant and Equipment; (4) Number of Employees; (5) FTE Work Estimate; (6) General/Corporate.

8. Human resources

Human resources refers to the establishment and administration of policies and assuring compliance with legal requirements in the areas of employment, compensation, benefits and employee health and safety. It also involves providing payroll and employee benefit administration, employee training and development, recruiting and staffing services, employee communications and labor relations management. Allocation Factors – (1) Number of Employees.

9. Information technology

Information technology refers to telecommunications and electronic data processing services such as computer operations, software development and maintenance, network support, end-user support, database administration and information systems security. Allocation Factors – (1) Number of Personal Computers; (2) Number of Clicks; (3) Number of Phone Lines; (4) Number of Employees; (5) Application Allocator; (6) Mainframe CPU and Disk Storage; (7) Number of Devices; (8) Number of Meters; (9)



Call Volume; (10) Square Footage; (11) Number of Radios; (12) Number of Mobile Data Devices; (13) Number of Customers; (14) Composite Allocator.

10. Legal services

Legal services refers to the provision of all types of legal advice and related services involving legal services related to corporate, commercial and contracts, litigation, regulatory, securities, real estate, legislative, employment and benefits, tax, intellectual property matters. In addition, services will also be provided to insurance (procurement, management and general advice), claims management, corporate records (policies, procedures and management) and compliance (compliance with laws, ethics and code of conduct). Allocation Factors – (1) General/Corporate.

11. Supply chain

Supply chain refers to the acquisition and provision of goods and services other than fuel, energy commodities or energy transmission. Specific activities include material inventory management, contract administration services, warehousing and logistics services and the establishment of standards. The category also encompasses the purchase and oversight for, and maintenance of, vehicles and related equipment. Allocation Factors – (1) Total Spend; (2) Number of Fleet Assets; (3) Dollars Associated with Number of Inventory Issues; (4) Composite Allocator.

12. Gas engineering

Gas engineering refers to engineering support to gas distribution operations. Such support includes designing and monitoring the construction and maintenance of gas distribution lines and ensuring that construction activity is consistent with plans. It also involves coordinating the planning and operation of gas distribution systems, performing operational reviews of completed construction, maintenance work of gas distribution lines and operating meter shops. Gas Engineering will also provide competitive excellence stewardship support and project management for gas distribution projects. Allocation Factors – (1) Feet of Installed/Replaced Pipeline; (2) Number of Meters Repaired; (3) FTE Work Estimate; (4) Number of Union Employees.

13. Gas supply

Gas supply refers to administrative functions related to purchasing, marketing and selling natural gas (including hedging and other risk management tools); scheduling, interrupting and curtailing natural gas deliveries; acquiring, selling, releasing and managing pipeline transportation capacity or storage capacity; gas control operations; and operating utility-owned underground gas storage fields. This function excludes all functions that are not ministerial in nature and excludes contract ownership, as each Client Company will continue to hold gas supply and



capacity contracts in its own name. Allocation Factors – (1) Gas Throughput; (2) Peak Day Capacity; (3) FTE Work Estimate.

14. Customer relations

Customer relations refers to the provision of services and systems dedicated to customer service, including meter reading and billing, credit, collections, customer relations, call center operations, revenue assurance, account management, market research and customer strategy. Allocation Factors – (1) Number of Customers; (2) Number of Transportation Customers.

15. Project Services

Project services refers to provide project management functions throughout the project life cycle from problem definition and concept development to project execution and performance validation. Offerings to affiliates include participation in business planning, Project Support Office services, problem solving and concept development, business case development, competitive excellence process improvement services, portfolio management, project management, and Dam safety program management. Allocation Factors – (1) Hydro MW Distribution; (2) FTE work estimate; (3) Specific Project Assignment.



Exhibit C – Reg AIA

Costs will be allocated through a tiered approach. This allocation methodology reflects operational aspects of the charge and applies costs in a meaningful and impartial method. First and foremost, costs will be directly charged whenever appropriate and practicable. Direct charging is essentially a “100% allocation” of costs related to a particular service to the one entity receiving that service. Second, where direct charging is not appropriate, costs will be allocated using cost causation principles that link costs related to a specific type of service to the customers receiving such service. All other cost allocations will be broad based with a generalized cost basis proxy. Specific Allocation Factors: Number of Customers – Based on the average number of customers (electric and/or gas) at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Employees - Based on the average number of employees included in the budget that is being prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Union Employees - Based on the average number of union employees at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Meters – Based on the average number of meters (electric and/or gas) at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances.



Number of Invoices Processed – Based on the average number of invoices processed at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Transactions – Based on the average number of transactions processed in the system at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Personal Computers – Based on the average number of personal computers at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Phone Lines – Based on the average number of phone lines at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Mainframe CPU and Disk Storage – Based on the number of CPU cycles used by the application divided by the total number of used CPU cycles and the total bytes of data storage used by the application divided by the total bytes used for mainframe storage for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Clicks – Based on the average number of clicks on the website page at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances.



Number of Devices – Based on the number of devices at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Mobile Data Devices – Based on the average number of mobile data devices at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Radios – Based on the number of radios for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Dollars Associated with Number of Imprints – Based on the dollars associated with the number of imprints for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Office Moves – Based on the average number of office moves for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Total Spend – Based on the average total spend at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Total Property, Plant and Equipment – Based on average property, plant and equipment at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this



factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Square Footage – Based on average square footage occupied for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Call Volume – Based on average call volume of the most recent calendar year at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Application Allocator – Based on the allocation of the specific application being worked on. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Specific Project Assignment - This indicates that Project Services is allowed to use any one of the existing allocation factors in this Exhibit C, such that costs associated with Project Services are allocated based on the nature of the project they are supporting. Full Time Equivalent (FTE) Work Estimate – Based on a recurring, predictable level of service. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Composite Allocator Based on Total Historical Billings for an IBS functional service as defined in Exhibit B - Based on the total O&M billings for the most recent 12 months at the time the budget is prepared or total O&M billings for the previous calendar year. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service). This ratio will be determined annually and/or such time as may be required due to significant change in circumstance. General/Corporate – Based on an equal weighting of a 13-month average of assets (excluding hedge assets, goodwill, and non-ordinary assets) for the most recent 13 months at the time the budget is prepared and average annual O&M costs (excluding



fuel costs) for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Gas Throughput – Based on gas throughput in dekatherms (sales and transportation) for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Feet of Installed/Replaced Pipeline – Based on average number of feet installed/replaced for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Dollars Associated with Number of Inventory Issues – Based on the dollars associated with the number of inventory issues for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Fleet Assets – Based on the average number of fleet assets at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Hydro MW Distribution – Based on the percentage per hydro region of rated generation in megawatts (MW), the numerator of which is for an individual hydro region and the denominator of which is for all hydro regions. This ratio will be revised annually at budget time if there are additions or deletions of hydro units, or changes in ownership percentages of existing hydro units, within the hydro regions. Number of Meters Repaired – Based on the average number of meters repaired at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at



such time as may be required due to a significant change in circumstances. Peak Day Capacity (gas) – Based on the highest daily send out in therms (excluding transportation) for the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances. Number of Transportation Customers – Based on the average number of transportation customers at the end of the most recent 12 months at the time the budget is prepared. The numerator of which is for a Client Company and the denominator of which is for all Client Companies (or specific Client Companies receiving the service allocated per this factor, if not all Companies are receiving the service.) This ratio will be determined annually and/or at such time as may be required due to a significant change in circumstances.



Asset Ownership by Integrys Business Support

Type of Asset Allocation Method

PP&E Used in Operations N/A

Leases All leasehold costs included in space allocation pool. Allocation between IBS and other tenants based on square footage of usable space. IBS portion of cost included in space cost labor overhead. Special purpose space usage billed separately based on specific use.

Leasehold Improvements Includes depreciation, return, and non-capitalized costs in space allocation cost pool. Allocation between IBS and other tenants based on square footage of usable space. IBS portion of cost included in space cost labor overhead. Special purpose space usage billed separately based on specific use.

Buildings Includes depreciation, return, and non-capitalized costs in space allocation cost pool. Allocation between IBS and other tenants based on square footage of usable space. IBS portion of cost included in space cost labor overhead. Special purpose space usage billed separately based on specific use.

Furniture, Equipment and PCs Includes depreciation, return, and non-capitalized costs in space allocation cost pool.

Telecommunications, Excluding Equipment Specifically Used for Gas or Energy Supply Control

Includes depreciation, return, and non-capitalized costs. Allocated by number of phone lines.

Large Equipment in Print/Copy Shop and Inserters Charge based on service provided. Total number of imprints.

Mainframe/ Servers Includes depreciation, return and non-capitalized costs. Allocated by number of personal computers.

Software Includes depreciation, return and non-capitalized costs in Software pool. Allocate to each company based on specific application allocators, as appropriate.

Miscellaneous IT Equipment (e.g. tape drives, special storage units, UPS equipment, etc)

Includes depreciation, return and non-capitalized costs. Allocation based on corporate cost allocator.

Environmental Equipment and Vehicles, including Water Quality Equipment, Lab Equipment, Boat, ATV, and Dataloggers

Includes depreciation, return and non-capitalized costs in Environmental equipment cost pool. Allocation based on allocation of services from Environmental area. Total Environmental labor billings.



Page 1 of 1

STATE OF MICHIGAN




LISA J. GAST, CPA

FOR


June 7, 2013

1

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

LISA J. GAST, CPA PART I


A. My name is Lisa J. Gast. My business address is Integrys Business Support, LLC 2

(“IBS”), 700 North Adams Street, P.O. Box 19001, Green Bay, WI 54307-9001. I am 3

Manager, Financial Planning and Analysis in the Treasury Department of Integrys 4

Energy Group, Inc (“Integrys”). Both IBS and Michigan Gas Utilities Corporation 5

(“MGUC”) are wholly-owned subsidiaries of Integrys. Integrys resulted from the 6

February 21, 2007 merger between WPS Resources Corporation and Peoples 7

Energy Corporation. 8

9



12


A. I graduated from the University of Wisconsin – Green Bay in 1984 with a Bachelor’s 14

Degree in Accounting. I received a Masters Degree in Business Administration 15

(“MBA”) from the University of Wisconsin - Oshkosh in 1995. My professional 16

designations are Certified Public Accountant (“CPA”) and Certified Treasury 17

Professional (“CTP”). I joined the Treasury Department at Wisconsin Public Service 18

2

Corporation (“WPS Corp”) in April of 2001. In my current position, I am responsible 1

for the capital structure forecasts for each of our regulated utilities. 2

3

Q. Have you previously testified in any regulatory proceedings? 4

A. Yes, I have. I have filed testimony before the Michigan Public Service Commission 5

(“MPSC”) on behalf of Michigan Gas Utilities Corporation (“MGUC”) in Case Nos. U-6

15549 and U-15990 and on behalf of Upper Peninsula Power Company (“UPPCO”) 7

in Case Nos. U-15988, U-16166 and U-16417. I have also testified regarding capital 8

structure and cost of capital before utility commissions in Illinois, Minnesota and 9

Wisconsin. 10

3

LISA J. GAST, CPA DIRECT TESTIMONY

PART II


A. The purpose of my pre-filed direct testimony is to: 2 3

1. Present MGUC’s capital structure and cost of capital for the 2012 historic 4 test year, 5

6 2. Present MGUC’s capital structure and cost of capital for the 2014 7

projected test year, 8 9 3. Explain the differences in adjusted common equity between the 2012 10

historic test year and the 2014 projected test year, 11 12 4. Describe the required Common Equity Ratio for the 2014 projected test 13

year, and 14 15 5. Describe the required Return on Common Equity (“ROE”) for the 2014 16

projected test year. 17 18


A. Yes, I am. I am sponsoring Schedules D1 through D5 of Exhibit A-4 (LJG-1) for the 20

2014 projected test year, and Schedules D1 through D8 of Exhibit A-14 (LJG-2) for 21

the 2012 historic test year. 22

23



26

Q. Please explain Schedules D1 through D5 of Exhibit A-4 (LJG-1). 27

A. In general, Schedules D1 through D5 of Exhibit A-4 (LJG-1) support and calculate 28

MGUC’s capital structure, cost of capital, and required rate of return for the 2014 29


31

4

Schedule D1 develops MGUC’s 2014 projected test year overall rate of return of 1

6.4020%, as shown on Line 24, based on MGUC’s 13-month average capital 2

structure, and a 10.75% ROE. 3

4

Schedule D2 develops MGUC’s 2014 projected test year embedded cost of long 5

term debt of 5.3105%, based on a 13-month average, as shown on Line 24. There 6

is one new debt issue forecasted for the test year, a $10,000,000 offering issued on 7

April 1, 2014 with an interest rate of 4.35%. 8

9

Schedule D3 develops MGUC’s 2014 projected test year cost of short-term debt of 10

1.5150%, based on a 13-month average, as shown on Line 28. 11

12

Schedule D4 indicates that MGUC has no preferred equity outstanding, as shown on 13

Line 2. 14

15

Schedule D5 develops MGUC’s 13-month average balance of Adjusted Common 16

Equity of $88,627,509 for the 2014 projected test year, as shown on Line 16. MGUC 17

requests a 10.75% ROE for the 2014 projected test year in this general rate case 18

proceeding, as supported by Mr. Paul R. Moul’s testimony and analysis. 19

20

Q. Please explain Schedules D1 through D8 of Exhibit A-14 (LJG-2). 21

A. In general, Schedules D1 through D8 of Exhibit A-14 (LJG-2) support and calculate 22

MGUC’s capital structure, cost of capital, and required rate of return for the 2012 23

historic test year. 24

25

5

Schedule D1 develops MGUC’s 2012 historic test year overall rate of return of 1

7.1076%, as shown on Line 22, based on MGUC’s 13-month average capital 2

structure, and a 10.75% ROE. 3

4

Schedule D2 develops MGUC’s 2012 historic test year embedded cost of long term 5

debt of 5.9089%, based on a 13-month average, as shown on Line 24. 6

7

Schedule D3 develops MGUC’s 2012 historic test year cost of short-term debt of 8

101.5424%, based on a 13-month average, as shown on Line 28. The interest rate 9

on short-term debt before the amortization of credit facility upfront fees is 0.15%. 10

11

Schedule D4 indicates that MGUC has no preferred equity outstanding, as shown on 12

Line 2. 13

14

Schedule D5 develops MGUC’s 13-month average balance of Adjusted Common 15

Equity of $83,247,890, for the 2012 historic test year, as shown on Line 16. 16

17

Schedule D6 provides the current and historic credit ratings along with the 18

associated outlooks for senior unsecured debt, junior subordinated debt, and 19

commercial paper for MGUC’s parent, Integrys, as published by Standard and Poor’s 20

(“S&P”), and Moody’s Investors Service (“Moody’s”). Integrys is not rated by Fitch 21

Ratings, and has no senior secured debt. MGUC is not rated by any service. 22

23

Schedule D7 presents information on utility corporate bond issuances for January 24

2013 through June 2013. MGUC last issued $15 million of 3.00% 10 year debt on 25

April 1, 2013 as partial replacement of their $28 million 7 year 5.72% debt that 26

6

matured 4/1/2013. Integrys was the lender. This debt issue was included in the 1

forecast at 3.25%. 2

3

Schedule D8 calculates financial metrics on both a financial and ratemaking basis for 4

historic years 2008 – 2012, and the 2014 projected test year, with and without rate 5

relief. 6

7

Q. Does MGUC present any other evidence on cost of capital? 8

A. Yes, it does. Mr. Paul R. Moul of P. Moul & Associates provides evidence on 9

MGUC’s cost of equity. He presents analytical studies employing various industry 10

models. 11

12

Q. Is MGUC publicly traded? 13

A. No, it is not. Integrys holds 100% of the common stock of MGUC. Integrys is traded 14

on the New York Stock Exchange under the symbol “TEG”. 15

16

Q. How were interest rates on short-term debt forecasted? 17

A. Short-term debt interest rates were derived based on the sum of the 2014 forecasted 18

1 month non-financial commercial paper rates and the 2012 average spread 19

between A2/P2 and AA commercial paper. The short-term interest rates also reflect 20

MGUC’s allocation of the costs of credit facilities held by Integrys. 21

22

Q. How was the forecasted rate for the 2014 intercompany long-term debt from 23

Integrys calculated? 24

A. The forecasted rate was estimated using the 10 Year Treasury rate forecasted for 25

the quarter of issuance, rounded to the nearest 5 basis points plus a credit spread of 26

7

110 basis points and issuance spread of 10 basis points. (3.15 + 1.10 + 0.10 = 4.35 1

forecasted rate) 2

3

Changes to MGUC’s Adjusted Common Equity from 2012 to 2014 4 Q. Please explain why MGUC’s year end adjusted common equity increased from 5

$83,003,919 for the 2012 historic test year to $94,444,154 for the 2014 projected 6

test year without rate relief, and to $94,356,197 for the 2014 projected test year 7

with rate relief. 8

A. The change in MGUC’s year end adjusted common equity is due to equity returns to 9

Integrys, retained earnings, increases in compensation related accounts and 10

reductions in utility equity adjustments. A summary of these changes with and 11

without rate relief is included in the following table. 12

* Includes Equity Adjustments for Goodwill, Tradename, and associated 13 Deferred Taxes. 14

15 ** Reduced Utility Equity Adjustment results from Deferred Tax cash 16 flows related to Goodwill and Tradename. 17

18

Q. What is the basis for the Adjusted Common Equity reflected on Schedules D1 19

of Exhibit A-14 (LJG-2) and Exhibit A-4 (LJG-1)? 20

A. These amounts reflect the average balances in common equity after adjustments for 21

non-utility investments, see Workpapers - 2012, pages 119 and 120 and Workpapers 22

– 2014, pages 119 and 120. These investments are primarily goodwill and 23

tradename related to the acquisition of MGUC by Integrys in 2006. Goodwill and 24

Common Equity Without Rate Relief With Rate Relief Actual 12/31/12* $83,003,919 $83,003,919 Equity Returns (7,000,000) (12,000,000)

Retained Earnings 9,095,475 14,007,518 Compensation Related Accounts 169,178 169,178

Reduced Utility Equity Adjustment** 9,175,582 9,175,582 Projected TY 12/31/14 $94,444,154 $94,356,197

8

tradename are being excluded from the common equity balances because they are 1

assumed to be funded with common equity capital (i.e., all MGUC debt is assumed 2

to support utility operations). Additionally, the deferred income taxes related to the 3

non-utility investments were adjusted as well to arrive at the deferred income taxes 4

supporting utility operations. 5

6

Q. What amount of equity in the capital structure do you feel is appropriate for 7

MGUC? 8

A. A common equity ratio of 50% to 55% (after considering adjustments related to non-9

utility investments) is required to provide MGUC the financial health and flexibility it 10

requires to respond to the changes and challenges of the utility industry. 11

12

MGUC is currently targeting a common equity ratio of 50.12% for the 2014 projected 13

test year. During the 2012 historic test year, MGUC maintained a 49.71% common 14

equity ratio. 15

16

Business risk is greater today than in earlier decades and this increased business 17

risk is reflected in the more stringent benchmarks now being used by the various 18

credit rating agencies. Business risk can be offset somewhat with decreased 19

financial risk by maintaining a lower debt ratio which, in turn, increases interest 20

coverage. 21

22

Q. What benefits does a capital structure with a higher equity ratio provide? 23

A. An adequate equity ratio provides the ability to resist negative financial pressures 24

and creates a buffer to protect against unexpected adverse developments so that 25

distortions can be quickly remedied without impairing either the orderly conduct of 26

the business, or the credit quality of present or future securities issues. This will help 27

9

ensure that MGUC has access to capital at reasonable rates when MGUC needs it, 1

thereby benefiting its customers. 2

3

The Required ROE 4 Q. What is MGUC’s recommendation for the cost of equity capital for MGUC? 5

A. MGUC is requesting a 10.75% ROE for the 2014 projected test year as described in 6

the pre-filed direct testimony of Mr. Paul R. Moul. 7

8

Q. Is the market responsive to alternative investment opportunities? 9

A. Yes, it is. Investors have a full field of investment choices. Investors can choose the 10

stock market or other markets such as bonds, treasury securities, money funds, real 11

estate, etc. If investors choose the stock market, they may elect a utility stock or a 12

stock from one of the many other industries available. If investors prefer utilities, 13

they have many to select from within the utility industry. Therefore, it is imperative to 14

provide a competitive return to the shareholder. The return on a utility's stock must 15

be competitive to other investment alternatives with similar risk profiles. 16

17

An adequate ROE is of major importance and benefit to customers. Adequate 18

returns on MGUC's common equity would help to ensure continued reliable utility 19

services, and would assure these services are provided at the lowest overall rates 20

through the lowest overall cost of capital. This can only be maintained with an 21

adequate ROE. 22

23

Q. What effect would a fair return on common equity have on the other securities 24

of MGUC? 25

A. An adequate ROE would permit MGUC to raise capital when needed, at reasonable 26

rates, especially during periods of “tight” credit markets. 27

28

10

Q. In summary, what is your recommendation regarding the required common 1

equity ratio and the required ROE for the 2014 projected test year? 2

A. MGUC recommends that the average common equity ratio be set at 50.00% with a 3

ROE of 10.75%. These values are recommended because: 4

1. They provide a fair return to investors commensurate with competitive 5 investment vehicles available, 6

7 2. They reflect the business risk associated with the utility industry, and 8 9 3. They recognize that MGUC has delivered, and will continue to deliver, 10

reliable service at a reasonable cost to its customers. Therefore, the 11 shareholder should be properly compensated for delivering on its 12 commitment to those customers. 13

14


A. Yes, it does. 16

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-4 (LJG-1)Rate of Return Summary Schedule: D1For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1

Witness: Lisa Gast, CPA

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)

Percent Percent Percent WeightedLine Permanent of Total Cost Permanent Total Conversion Pre-Tax Capital CostNo. Description Amount (1) Capital (2) Capital Rate % Capital (2) Cost % Factor Return Incl ST Incl ST12 Long-Term Debt 78,083,333$ 46.84% 37.20% 5.3105% (3) 2.49% 1.9755% 1.9755% 44.16% 2.3449%34 Preferred Stock -$ 0.00% 0.00% 0.0000% (4) 0.00% 0.0000% 0.0000% 0.00% 0.0000%56 Common Shareholders' Equity 88,627,509$ 53.16% 42.22% 10.7500% (5) 5.71% 4.5387% 1.637 7.4285% 50.12% 5.3879%78 Total Permanent Capital 166,710,842$ 100.00% 8.20%9

10 Short-Term Debt 10,120,489$ 4.82% 1.5150% (6) 0.0730% 0.0730% 5.72% 0.0867%1112 Job Development - ITC - Debt13 Job Development - ITC Equity14 Total Job Development - ITC -$ 0.00% 8.2023%1516 Deferred Income Taxes (Net) - MBT -$ 0.00%1718 Deferred Income Taxes (Net) - Federal 38,072,890$ 18.14% 0.0000% 0.0000% 0.0000%1920 Deferred Tax Proration 23,958$ 0.01% 7.8195% 0.0009% 0.0009%2122 Capital Structure Adjustments (5,003,188)$ -2.38% 7.8195% (7) -0.1861% -0.1861%2324 Total 209,924,991$ 100.01% 6.4020% 9.2918% 100.00% 7.8195%

Memo Only:DITC 568,158$ Liabilities & Equity 210,493,149$

(1) See Exh. A-2, Sch. B1(2) Excludes Short-Term Debt, Deferred Job Development Investment Tax Credit, Deferred Investment

Tax Credit and Deferred Income Taxes to calculate the rate of return for Job DevelopmentInvestment Tax Credit purposes in accordance with Internal Revenue Service Income TaxRegulation Section 1.46-6

(3) See Exh. A-4, Sch. D2(4) See Exh. A-4, Sch. D4(5) See Exh. A-4, Sch. D5(6) See Exh. A-4, Sch. D3(7) See row 22, column k

Schedule D1

Capital StructureWeighted Cost

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-4 (LJG-1)Cost of Long-Term Debt Schedule: D2For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)

Net CostUnderwriting Proceeds Based

Original Stated Interest Amount Price to & Financing to the on Net AmountLine Issue Maturity Rate of Public Expenses Company Proceeds Out- AnnualNo. Description Date Date (%) Offering (%) (%) (%) (%) standing Cost12 Mortgage Bonds3 -$ 4 - 5 - 6 - 7 - 8 Total Mortgage Bonds -$ 910 Other Long-Term Debt11 4/1/2006 4/1/2016 5.76% 28,000,000 28,000,000 - 28,000,000 5.84% 28,000,000 1,635,200 12 4/1/2006 4/1/2021 5.98% 28,000,000 28,000,000 - 28,000,000 6.06% 28,000,000 1,696,800 13 4/1/2013 4/1/2023 3.25% 15,000,000 15,000,000 - 15,000,000 3.25% 15,000,000 487,500 14 4/1/2014 4/1/2024 4.35% 10,000,000 10,000,000 - 10,000,000 4.35% 7,083,333 308,125 15 Total Other Long-Term Debt 78,083,333$ 4,127,625$ 1617 Total Long-Term Debt 78,083,333$ 181920 Adjust to interest booked - 18,9812122 Total Long-Term Debt Balance 78,083,333$ 4,146,606$ 2324 Cost of Long-Term Debt 5.3105%

Schedule D2

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-4 (LJG-1)Cost of Short-Term Debt Schedule: D3For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c)

Line Balance TotalNo. Month Outstanding Cost12 Inter-Company Loans3 Dec 17,931,344$ 4 Jan 22,606,827 5 Feb 20,947,476 6 Mar 17,232,539 7 Apr 4,050,122 8 May 2,044,004 9 Jun 1,100,430 10 Jul 2,073,037 11 Aug 3,569,199 12 Sep 7,747,061 13 Oct 12,435,738 14 Nov 12,845,104 15 Dec 11,657,320 16 13 month Average 10,120,489$ 62,935 1718 Commercial Paper - - 1920 Letter of Credit - - 2122 Other - - 2324 Amortization of Upfront Fees 90,392 2526 Total 10,120,489$ 153,327$ 2728 Average Cost of Short-Term Debt 1.5150%

Schedule D3

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-4 (LJG-1)Cost of Preferred Stock Schedule: D4For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Total ValueAnnual Discount Net Number of Cost Annual

Line Dividend Par or Finance Proceeds of Shares Outstanding Rate DollarNo. Description Required Value Premium Expenses Received Outstanding Proceeds (%) Amount12 None

Schedule D4

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-4 (LJG-1)Cost of Common Shareholders' Equity Schedule: D5For the 12 Month Period Ended, December 31, 2014 Page: 1 of 1


AdjustedLine CommonNo. Stock12 Dec 90,437,4623 Jan 93,658,5924 Feb 92,542,5315 Mar 88,647,8216 Apr 84,822,6727 May 85,295,9868 Jun 85,270,6429 Jul 85,298,605

10 Aug 85,535,42311 Sep 88,606,72412 Oct 89,609,32513 Nov 91,800,97414 Dec 94,444,1541516 Average $88,627,509 10.7500%

Schedule D5

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-14 (LJG-2)Rate of Return Summary Schedule: D1For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)

Percent Percent Percent WeightedLine Permanent of Total Cost Permanent Total Conversion Pre-Tax Capital CostNo. Description Amount (1) Capital (2) Capital Rate % Capital (2) Cost % Factor Return Incl ST Incl ST12 Long-Term Debt 84,000,000$ 50.22% 43.41% 5.9089% (3) 2.97% 2.5651% 2.5651% 50.16% 2.9641%34 Preferred Stock -$ 0.00% 0.00% 0.0000% (4) 0.00% 0.0000% 0.0000% 0.00% 0.0000%56 Common Shareholders' Equity 83,247,890$ 49.78% 43.03% 10.7500% (5) 5.35% 4.6257% 1.637 7.5709% 49.71% 5.3442%78 Total Permanent Capital 167,247,890$ 100.00% 8.32%9

10 Short-Term Debt 206,250$ 0.11% 101.5424% (6) 0.1082% 0.1082% 0.12% 0.1251%1112 Job Development - ITC - Debt13 Job Development - ITC Equity14 Total Job Development - ITC -$ 0.00% 8.3186%1516 Deferred Income Taxes (Net) - MBT -$ 0.00%1718 Deferred Income Taxes (Net) - Federal 30,422,678$ 15.72% 0.0000% 0.0000% 0.0000%1920 Capital Structure Adjustments (4,391,294)$ -2.27% 8.4334% (7) -0.1914% -0.1914%2122 Total 193,485,524$ 100.00% 7.1076% 10.0528% 100.00% 8.4334%

Memo Only:DITC 590,744$ Liabilities & Equity 194,076,268$

(1) See Exh. A-2, Sch. B1(2) Excludes Short-Term Debt, Deferred Job Development Investment Tax Credit, Deferred Investment

Tax Credit and Deferred Income Taxes to calculate the rate of return for Job DevelopmentInvestment Tax Credit purposes in accordance with Internal Revenue Service Income TaxRegulation Section 1.46-6

(3) See Exh. A-4, Sch. D2(4) See Exh. A-4, Sch. D4(5) See Exh. A-4, Sch. D5(6) See Exh. A-4, Sch. D3(7) See row 22, column k

Schedule D1

Capital StructureWeighted Cost

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-14 (LJG-2)Cost of Long-Term Debt Schedule: D2For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)

Net CostUnderwriting Proceeds Based

Original Stated Interest Amount Price to & Financing to the on Net AmountLine Issue Maturity Rate of Public Expenses Company Proceeds Out- AnnualNo. Description Date Date (%) Offering (%) (%) (%) (%) standing Cost12 Mortgage Bonds3 -$ 4 - 5 - 6 - 7 - 8 Total Mortgage Bonds -$ 910 Other Long-Term Debt11 4/1/2006 4/1/2013 5.72% 28,000,000 28,000,000 - 28,000,000 5.82% 28,000,000 1,628,293 12 4/1/2006 4/1/2016 5.76% 28,000,000 28,000,000 - 28,000,000 5.86% 28,000,000 1,639,680 13 4/1/2006 4/1/2021 5.98% 28,000,000 28,000,000 - 28,000,000 6.08% 28,000,000 1,702,307 1415 Total Other Long-Term Debt 84,000,000$ 4,970,280$ 1617 Total Long-Term Debt 84,000,000$ 181920 Adjustment to booked interest - -6,7902122 Total Long-Term Debt Balance 84,000,000$ 4,963,490$ 2324 Cost of Long-Term Debt 5.9089%

Schedule D2

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-14 (LJG-2)Cost of Short-Term Debt Schedule: D3For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c)

Line Balance TotalNo. Month Outstanding Cost12 Inter-Company Loans3 Dec -$ 4 Jan 2,300,000 5 Feb - 6 Mar - 7 Apr - 8 May - 9 Jun - 10 Jul - 11 Aug - 12 Sep - 13 Oct - 14 Nov 175,000 15 Dec - 16 13 month Average 206,250$ 313 1718 Commercial Paper - - 1920 Letter of Credit - - 2122 Other - - 2324 Amortization of Upfront Fees 209,118 2526 Total 206,250$ 209,431$ 2728 Average Cost of Short-Term Debt 101.5424%

Schedule D3

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-14 (LJG-2)Cost of Preferred Stock Schedule: D4For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


(a) (b) (c) (d) (e) (f) (g) (h) (i) (j)

Total ValueAnnual Discount Net Number of Cost Annual

Line Dividend Par or Finance Proceeds of Shares Outstanding Rate DollarNo. Description Required Value Premium Expenses Received Outstanding Proceeds (%) Amount12 None

Schedule D4

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-14 (LJG-2)Cost of Common Shareholders' Equity Schedule: D5For the 12 Month Period Ended, December 31, 2012 Page: 1 of 1


AdjustedLine CommonNo. Stock12 Dec 82,093,6353 Jan 84,593,4004 Feb 86,988,0975 Mar 82,335,4516 Apr 83,590,8327 May 83,404,7218 Jun 82,866,0349 Jul 82,845,736

10 Aug 82,831,78611 Sep 81,631,17112 Oct 81,924,39413 Nov 83,414,28014 Dec 83,003,9191516 Average $83,247,890 10.7500%

Schedule D5

Case No. U-17273Witness: Lisa J. Gast

Exhibit A-14 (LJG-2)Schedule D6

Page 1 of 1

S&P Credit Ratings

Senior Unsecured Junior

Subordinated Commercial Paper Outlook24-Jan-2012 BBB+ BBB A-2 Stable21-Jan-2011 BBB BBB- A-2 Positive26-Jan-2010 BBB BBB- A-2 Stable5-Mar-2009 BBB BBB- A-2 Negative

25-Nov-2008 BBB+ BBB A-2 Negative

Moody's Credit Ratings

Senior UnsecuredJunior

Subordinated Commercial Paper Outlook27-May-2010 Baa1 Baa2 P-2 Stable9-Jun-2009 Baa1 Baa2 P-2 Negative9-Mar-2009 A3 Baa1 - Watch Negative9-Mar-2009 - - P-2 Stable

(a) Integrys' Corporate Credit Rating was rated A- by S&P as of January 24, 2012.(b) Integrys' Corporate Credit Rating was rated BBB+ by S&P as of June 1, 2009. (c) MGUC is not rated by any agency.(d) Integrys is not rated by Fitch.(e) Integrys has no Senior Secured.


Credit Rating Data for Parent, Integrys Energy Group, Inc.



Page 1 of 1

Issue Date Issuing Company Offering Type

Offering Amount

(Millions)Coupon

RateMaturity

DateOffering

StructureMoody's Rating S&P Rating Spread

1/3/2013 Virginia Electric and Power Company Unsecured $250 1.200% 1/15/2018 NC4 A3 A- 0.450%1/3/2013 Virginia Electric and Power Company Unsecured $500 4.000% 1/15/2043 NC30 A3 A- 0.930%1/7/2013 Public Service Electric and Gas Company Secured $400 3.800% 1/1/2043 NC30 A1 A 0.736%1/8/2013 Duke Energy Corporation Unsecured $17 3.100% 3/15/2025 NCL Baa2 BBB 1.210%1/8/2013 South Carolina Electric & Gas Co. Secured $15 3.625% 2/1/2033 NCL 0.000%1/8/2013 South Carolina Electric & Gas Co. Secured $39 4.000% 2/1/2028 NCL 0.000%1/8/2013 Connecticut Light and Power Company Secured $400 2.500% 1/15/2023 NC10 A 0.700%1/9/2013 Entergy Arkansas, Inc. Secured $55 1.550% 10/1/2017 NCL A3 0.000%1/9/2013 Entergy Arkansas, Inc. Secured $45 2.375% 1/1/2021 NCL A3 0.000%1/9/2013 Duke Energy Corporation Unsecured $500 5.125% 1/15/2073 NC5 Baa3 BBB- 2.065%

1/15/2013 NextEra Energy Capital Holdings, Inc Unsecured $425 5.000% 1/15/2073 NC5 Baa2 BBB 1.980%1/31/2013 Central Maine Power Company Secured $225 4.450% 1/15/2043 NCL 0.000%2/8/2013 PPL Energy Supply, LLC Unsecured $212 4.600% 12/15/2021 NC10 Baa2 BBB 0.000%

2/12/2013 Exelon Generation Company, LLC Unsecured $523 4.250% 6/15/2022 NC10 Baa2 BBB 0.000%2/12/2013 Exelon Generation Company, LLC Unsecured $788 5.600% 6/15/2042 NC30 Baa2 BBB 0.000%2/25/2013 Consolidated Edison Company of New York, Inc. Unsecured $700 3.950% 3/1/2043 NC30 A- 0.880%2/28/2013 AEP Texas North Company Unsecured $125 3.090% 2/28/2023 NCL 0.000%2/28/2013 AEP Texas North Company Unsecured $75 4.480% 2/27/2043 NCL 0.000%2/28/2013 FirstEnergy Corp. Unsecured $650 2.750% 3/15/2018 NC5 BB+ 2.000%2/28/2013 FirstEnergy Corp. Unsecured $850 4.250% 3/15/2023 NC10 BB+ 2.375%3/4/2013 Southern California Edison Co. Secured $400 3.900% 3/15/2043 NC30 A1 A 0.830%3/6/2013 Hawaiian Electric Industries, Inc. Unsecured $50 3.990% 3/6/2023 Callable 0.000%3/6/2013 Tucson Electric Power Company Unsecured $91 4.000% 9/1/2029 NC10 Baa3 1.130%3/7/2013 Carolina Power & Light Company Secured $500 4.100% 3/15/2043 NC30 A1 A 0.930%

3/11/2013 Duke Energy Corporation Unsecured $4 3.150% 3/15/2027 NCL BBB 1.080%3/11/2013 Kansas City Power & Light Company Unsecured $300 3.150% 3/15/2023 NC10 Baa2 BBB 1.100%3/11/2013 Potomac Electric Power Company Secured $250 4.150% 3/15/2043 NC30 A3 A 0.900%3/11/2013 Virginia Electric and Power Company Unsecured $500 2.750% 3/15/2023 NC10 A3 A- 0.720%3/12/2013 Georgia Power Company Unsecured $400 4.300% 3/15/2043 Callable A3 A 1.100%3/12/2013 Metropolitan Edison Company Unsecured $300 3.500% 3/15/2023 Callable Baa2 BBB- 1.500%3/12/2013 PPL Capital Funding, Inc. Secured $400 5.900% 4/30/2073 NC5 Ba1 BB+ 2.680%3/13/2013 Indiana Michigan Power Company Unsecured $250 3.200% 3/15/2023 NC10 Baa2 BBB 1.200%3/18/2013 AEP Transmission Company, LLC Secured $25 4.830% 3/18/2043 NCL 0.000%3/18/2013 Duke Energy Corporation Unsecured $5 3.350% 3/15/2027 NCL Baa2 BBB 1.390%3/19/2013 Arizona Public Service Company Unsecured $100 4.500% 4/1/2042 NC28 Baa1 BBB+ 1.050%3/19/2013 CMS Energy Corporation Unsecured $250 4.700% 3/31/2043 NC30 Baa3 BBB- 1.600%3/19/2013 DTE Electric Company Secured $375 4.000% 4/1/2043 NC30 A1 A 0.875%3/19/2013 Public Service Company of Colorado Secured $250 2.500% 3/15/2023 NC10 A2 A 0.650%3/19/2013 Public Service Company of Colorado Secured $250 3.950% 3/15/2043 NC30 A 0.850%3/21/2013 Westar Energy, Inc. Secured $250 4.100% 4/1/2043 NC30 A3 A- 0.950%3/25/2013 Duke Energy Corporation Unsecured $3 3.250% 3/15/2027 NCL Baa2 BBB 1.320%3/26/2013 Kansas City Power & Light Company Secured $31 1.250% 7/1/2017 NCL A3 0.000%3/26/2013 Kansas City Power & Light Company Secured $40 2.950% 12/1/2023 NC10 A3 0.000%3/26/2013 Kansas City Power & Light Company Secured $39 2.950% 12/1/2023 NC10 A3 0.000%4/1/2013 Duke Energy Corporation Unsecured $3 3.250% 6/15/2027 NCL Baa2 BBB 1.390%4/2/2013 ALLETE, Inc. Secured $50 1.830% 4/15/2018 Callable 0.000%4/2/2013 ALLETE, Inc. Secured $40 3.300% 10/15/2028 NC15 0.000%4/2/2013 ALLETE, Inc. Secured $60 4.210% 10/15/2043 NC30 0.000%4/2/2013 Texas-New Mexico Power Company Secured $93 6.950% 4/1/2043 Callable A3 A- 0.000%4/3/2013 Idaho Power Co. Secured $75 2.500% 4/1/2023 NC10 A2 A- 0.727%4/3/2013 Idaho Power Co. Secured $75 4.000% 4/1/2043 NC30 A2 A- 0.965%4/4/2013 ITC Midwest LLC Secured $100 4.090% 4/30/2043 NC30 0.000%4/9/2013 NiSource Finance Corporation Unsecured $750 4.800% 2/15/2044 NC30 Baa3 BBB- 1.875%

4/16/2013 Duke Energy Corporation Unsecured $17 3.000% 6/15/2025 NCL Baa2 BBB 1.250%4/25/2013 AES Corporation Unsecured $500 4.875% 5/15/2023 NC5 Ba3 BB- 3.160%

Note: Date Parameters: Jan 01, 2013-May 06, 2013

Source: SNL Financial

Utility Bond Issuances




Page 1 of 4

Rate Relief No Rate ReliefTest Year Test Year

Historical Source / Ending EndingLine Description Comment 12/31/2014 12/31/2014 12/31/2012 12/31/2011 12/31/2010 12/31/2009 12/31/2008

[A] [B] [C] [D] [E] [F] [G] [H] [I]

1 A EBIT Interest Coverage2 Total Operating Income FERC - Income Statement 13,482$ 8,571$ 9,969$ 12,675$ 10,416$ 12,432$ 10,657$ 3 Other Income and Deductions, net FERC - Income Statement [417 - 426.5] 11 11 26 772 41 (53,945) 171 4 Federal and State Income Taxes FERC - Income Statement [409.1- 411.4] 5,927 2,804 3,091 5,181 4,470 4,972 3,297 5 AFUDC Equity Funds Portion FERC - Income Statement - - (14) 31 - - - 6 EBIT Sum of Lines 2-4, - Line 5 19,420$ 11,387$ 13,100$ 18,597$ 14,926$ (36,540)$ 14,126$

7 Total Interest Charges FERC - Income Statement [427 - 431] 4,303$ 4,303$ 4,983$ 5,536$ 5,061$ 5,171$ 5,166$

8 EBIT Interest Coverage Line 6 / Line 7 4.51 2.65 2.63 3.36 2.95 (7.07) 2.73

9 B EBITDA Interest Coverage10 Total Operating Income 13,482$ 8,571$ 9,969$ 12,675$ 10,416$ 12,432$ 10,657$ 11 Depreciation and Amortization 9,780 9,780 8,116 7,923 10,098 7,463 7,30912 Other Income and Deductions, net 11 11 26 772 41 (53,945) 17113 Federal and State Income Taxes 5,927 2,804 3,091 5,181 4,470 4,972 3,29714 AFUDC Equity Funds Portion - - (14) 31 - - - 15 EBITDA Sum of the Above 29,200$ 21,166$ 21,188$ 26,583$ 25,024$ (29,077)$ 21,435$

16 Total Interest Charges Line 7 4,303$ 4,303$ 4,983$ 5,536$ 5,061$ 5,171$ 5,166$

17 EBITDA Interest Coverage Line 15 / Line 16 6.79 4.92 4.25 4.80 4.94 (5.62) 4.15

18 C FFO Interest Coverage19 Funds from Operations20 Net Income FERC - Income Statement 9,178$ 4,268$ 4,981$ 7,911$ 5,396$ (46,684)$ 5,663$ 21 Depreciation and Amortization 9,780 9,780 8,116 7,923 10,098 7,463 7,309 22 Deferred Income Tax and Investment Tax Credits (4,389) (4,389) 8,802 7,309 6,199 (27,668) 6,365 23 Other Operating Cash Flow 7,111 7,111 (2,880) 4,172 3,335 89,922 4,901 24 Total Funds from Operations Sum of the Above 21,680$ 16,769$ 19,019$ 27,315$ 25,028$ 23,033$ 24,238$ 25 Total Interest Charges Line 7 4,303 4,303 4,983 5,536 5,061 5,171 5,166 26 Funds from Operation plus Interest Sum of the Above 25,983$ 21,072$ 24,002$ 32,851$ 30,089$ 28,204$ 29,404$


28 FFO Interest Coverage Line 26 / Line 27 6.04 4.90 4.82 5.93 5.95 5.45 5.69

29 D Overall Fixed Charge Coverage:30 Net Income Line 20 9,178$ 4,268$ 4,981$ 7,911$ 5,396$ (46,684)$ 5,663$ 31 Total Interest Charges (Gross Interest) Line 7 4,303 4,303 4,983 5,536 5,061 5,171 5,166 32 Net Income plus Gross Interest Sum of the Above 13,482$ 8,571$ 9,964 13,447 10,457 (41,513) 10,829

33 Total Interest Charges (Gross Interest) Line 7 4,303$ 4,303$ 4,983$ 5,536$ 5,061$ 5,171$ 5,166$ 34 Preferred Dividends N/A35 Gross Interest plus Preferred Dividends Sum of the Above 4,303$ 4,303$ 4,983$ 5,536$ 5,061$ 5,171$ 5,166$

36 Overall Fixed Charge Coverage Line 32 / Line 35 3.13 1.99 2.00 2.43 2.07 (8.03) 2.10

37 E Cash Flow Coverage of Dividends N/A MGUC doesn't pay dividends38 F Common Dividend Payout Ratio N/A MGUC doesn't pay dividends

Note (1): The above ratios are on a financial basis.


Historical and Projected Financial Metrics - Financial Basis(000s)

Historical Year Ended



Page 2 of 4

Rate ReliefTest Year Test Year

Ending EndedLine Description Historical Source 12/31/2014 12/31/2014 12/31/2012 12/31/2011 12/31/2010 12/31/2009 12/31/2008

[A] [B] [C] [D] [E] [F] [G] [H] [I]

1 G Permanent Capitalization Balances & Percentages2 Capital Structure3 Long-term Debt GLN5117M 78,083 78,083 84,000 84,000 84,000 84,000 84,000 4 Preferred Stock N/A5 Unadjusted Common Equity GLN5117M 145,544$ 145,641$ 145,480$ 150,860$ 158,588$ 168,163$ 234,093$

6 Unadjusted Total Capital Sum of Lines 3 - 5 223,627$ 223,724$ 229,480$ 234,860$ 242,588$ 252,163$ 318,093$

7 Capital Structure Ratios - Financial8 Long-term Debt Ratio Line 3 / Line 6 34.92% 34.90% 36.60% 35.77% 34.63% 33.31% 26.41%9 Preferred Stock Ratio Line 4 / Line 6 - - - - - - - 10 Common Equity Ratio Line 5 / Line 6 65.08% 65.10% 63.40% 64.23% 65.37% 66.69% 73.59%

11 H Return on Equity (ROE)12 Financial ROE Line 20 from Page 1 / Line 5 6.31% 2.93% 3.42% 5.24% 3.40% -27.76% 2.42%13 Authorized ROE 10.75% 10.75% 10.75% 10.75% 10.45% 10.45%

14 I Total Capitalization Balances & Percentages15 Short-term Debt GLN5117M 10,217 10,120 206 1,288 3,891 8,864 19,611 16 Long-term Debt Line 3 Above 78,083 78,083 84,000 84,000 84,000 84,000 84,000 17 Preferred Stock Line 4 Above - - - - - - - 18 Unadjusted Common Equity Line 5 Above 145,544 145,641 145,480 150,860 158,588 168,163 234,093

19 Unadjusted Total Capital Sum of Lines 15 - 18 233,845$ 233,845$ 229,686$ 236,148$ 246,479$ 261,026$ 337,704$

20 Capital Structure Ratios - Financial21 Short-term Debt Ratio Line 15 / Line 19 4.37% 4.33% 0.09% 0.55% 1.58% 3.40% 5.81%22 Long-term Debt Ratio Line 16 / Line 19 33.39% 33.39% 36.57% 35.57% 34.08% 32.18% 24.87%23 Preferred Stock Ratio Line 17 / Line 19 - - - - - - - 24 Common Equity Ratio Line 18 / Line 19 62.24% 62.28% 63.34% 63.88% 64.34% 64.42% 69.32%

Note (1): The above ratios are on a financial basis.Note (2): Data is on a 13 month average basis



Historical and Projected Financial Metrics - Financial Basis(000s)



Page 3 of 4

Rate Relief No Rate ReliefTest Year Test Year

Historical Source / Ending EndingLine Description Comment 12/31/2014 12/31/2014 12/31/2012 12/31/2011 12/31/2010 12/31/2009 12/31/2008

[A] [B] [C] [D] [E] [F] [F] [F] [F]

1 A EBIT Interest Coverage2 Total Operating Income Jurisdictional Models 13,482$ 8,570$ 9,992$ 12,450$ 10,436$ 12,275$ 10,654$ 3 Other Income and Deductions, net - - - - - - - 4 Federal and State Income Taxes Jurisdictional Models 5,927$ 2,805$ 3,068$ 5,405$ 4,449$ 5,130$ 3,294$ 5 AFUDC Equity Funds Portion N/A - - - - - - - 6 EBIT Sum of Lines 2-4, - Line 5 19,409$ 11,375$ 13,060$ 17,856$ 14,885$ 17,405$ 13,948$

7 Total Interest Charges Jurisdictional Models 4,300$ 4,300$ 5,173$ 5,252$ 5,061$ 5,171$ 5,745$

8 EBIT Interest Coverage Line 6 / Line 7 4.51 2.65 2.52 3.40 2.94 3.37 2.43

9 B EBITDA Interest Coverage10 Total Operating Income Line 2 13,482$ 8,570$ 9,992$ 12,450$ 10,436$ 12,275$ 10,654$ 11 Depreciation and Amortization Line 21 9,780 9,780 8,116 7,923 10,098 7,463 7,30912 Other Income and Deductions, net - - - - - - - 13 Federal and State Income Taxes Line 4 5,927 2,805 3,068 5,405 4,449 5,130 3,29414 AFUDC Equity Funds Portion - - - - - - - 15 EBITDA Sum of the Above 29,189$ 21,155$ 21,176$ 25,779$ 24,983$ 24,868$ 21,257$


17 EBITDA Interest Coverage Line 15 / Line 16 6.79 4.92 4.09 4.91 4.94 4.81 3.70

18 C FFO Interest Coverage19 Funds from Operations20 Net Income Jurisdictional Models 9,181$ 4,270$ 4,819$ 7,199$ 5,375$ 7,104$ 4,909$ 21 Depreciation and Amortization GLN5250M 9,780 9,780 8,116 7,923 10,098 7,463 7,309 22 Deferred Income Tax and Investment Tax Credits GLN5250M 7,250 7,250 4,987 3,744 1,865 2,332 2,027 23 Other Operating Cash Flow 7,111 7,111 (2,880) 4,172 3,335 1,734 4,901 24 Total Funds from Operations Sum of the Above 33,322$ 28,411$ 15,042$ 23,037$ 20,673$ 18,633$ 19,146$ 25 Total Interest Charges Line 7 4,300 4,300 5,173 5,252 5,061 5,171 5,745 26 Funds from Operation plus Interest Sum of the Above 37,623$ 32,711$ 20,215$ 28,289$ 25,734$ 23,804$ 24,891$


28 FFO Interest Coverage Line 26 / Line 27 8.75 7.61 3.91 5.39 5.09 4.60 4.33

29 D Overall Fixed Charge Coverage:30 Net Income Line 20 9,181$ 4,270$ 4,819$ 7,199$ 5,375$ 7,104$ 4,909$ 31 Total Interest Charges (Gross Interest) Line 7 4,300 4,300 5,173 5,252 5,061 5,171 5,745 32 Net Income plus Gross Interest Sum of the Above 13,482$ 8,570$ 9,992 12,450 10,436 12,275 10,654

33 Total Interest Charges (Gross Interest) Line 7 4,300$ 4,300$ 5,173$ 5,252$ 5,061$ 5,171$ 5,745$ 34 Preferred Dividends N/A35 Gross Interest plus Preferred Dividends Sum of the Above 4,300$ 4,300$ 5,173$ 5,252$ 5,061$ 5,171$ 5,745$

36 Overall Fixed Charge Coverage Line 32 / Line 35 3.13 1.99 1.93 2.37 2.06 2.37 1.85

37 E Cash Flow Coverage of Dividends N/A MGUC doesn't pay dividends38 F Common Dividend Payout Ratio N/A MGUC doesn't pay dividends

Note (1): The above ratios are on a ratemaking basis.


Historical and Projected Financial Metrics - Ratemaking Basis(000s)




Page 4 of 4

Rate ReliefTest Year Test Year

Ending EndedLine Description Historical Source 12/31/2014 12/31/2014 12/31/2012 12/31/2011 12/31/2010 12/31/2009 12/31/2008

[A] [B] [C] [D] [E] [F] [F] [F] [F]

1 G Permanent Capitalization Balances & Percentages2 Capital Structure3 Long-term Debt Jurisdictional Models 78,083 78,083 84,000 84,000 84,000 84,000 84,000 4 Preferred Stock N/A5 Common Equity - Ratemaking Jurisdictional Models 88,531 88,628 83,248 84,734 88,544 96,582 102,036

6 Ratemaking Total Capital Sum of Lines 3 - 6 166,614$ 166,711$ 167,248$ 168,734$ 172,544$ 180,582$ 186,036$

7 Capital Structure Ratios - Ratemaking8 Long-term Debt Ratio Line 3 / Line 6 46.86% 46.84% 50.22% 49.78% 48.68% 46.52% 45.15%9 Preferred Stock Ratio Line 4 / Line 6 - - - - - - - 10 Common Equity Ratio Line 5/ Line 6 53.14% 53.16% 49.78% 50.22% 51.32% 53.48% 54.85%

11 H Return on Equity (ROE)12 Ratemaking Net Income Line 20 9,181$ 4,270$ 4,819$ 7,199$ 5,375$ 7,104$ 4,909$

13 Ratemaking ROE Jurisdictional Models 10.37% 5.23% 6.14% 8.45% 8.45% 8.45% 5.92%14 Authorized ROE 10.75% 10.75% 10.75% 10.75% 10.45% 10.45%

15 I Total Capitalization Balances & Percentages16 Short-term Debt Jurisdictional Models 10,217 10,120 206 1,288 3,891 8,864 19,611 17 Long-term Debt Line 3 78,083 78,083 84,000 84,000 84,000 84,000 84,000 18 Preferred Stock Line 4 - - - - - - - 19 Common Equity - Ratemaking Line 6 88,531 88,628 83,248 84,734 88,544 96,582 102,036 20 Total Capital Sum of Lines 16 - 19 176,831 176,831 167,454 170,022 176,435 189,446 205,647

21 Job Development - ITC - Debt - - - - - - - 22 Job Development - ITC - Equity (16,263,951) - - - - - - - 23 Total Job Development - ITC - - - - - - -

24 Deferred Investment Tax Credit Jurisdictional Models - - - - - 11 -

25 Deferred Income Taxes (Net) - Federal Jurisdictional Models 38,097 38,097 30,423 23,825 22,106 20,077 18,715

26 Capital Structure Adjustment Jurisdictional Models (5,003) (5,003) (4,391) (1,257) (3,981) (3,046) (11,252)

27 Ratemaking Total Capital Sum of Lines 20 - 26 209,925$ 209,925$ 193,486$ 192,589$ 194,560$ 206,488$ 213,109$

28 Percent Capital29 Short-term Debt Ratio Line 16 / Line 20 5.78% 5.72% 0.12% 0.76% 2.21% 4.68% 9.54%30 Long-term Debt Ratio Line 17 / Line 20 44.16% 44.16% 50.16% 49.41% 47.61% 44.34% 40.85%31 Preferred Stock Ratio Line 18 / Line 20 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%32 Common Equity Ratio Line 19 / Line 20 50.07% 50.12% 49.71% 49.84% 50.18% 50.98% 49.62%

Percent of Total Capital29 Short-term Debt Ratio Line 16 / Line 27 4.87% 4.82% 0.11% 0.67% 2.00% 4.29% 9.20%30 Long-term Debt Ratio Line 17 / Line 27 37.20% 37.20% 43.41% 43.62% 43.17% 40.68% 39.42%31 Preferred Stock Ratio Line 18 / Line 27 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%32 Common Equity Ratio Line 19 / Line 27 42.17% 42.22% 43.03% 44.00% 45.51% 46.77% 47.88%33 Job Development - ITC Ratio Line 23 / Line 27 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%34 Deferred Investment Tax Credit Ratio Line 24 / Line 27 0.00% 0.00% 0.00% 0.00% 0.00% 0.01% 0.00%35 Deferred Income Taxes (Net) - Federal - Ratio Line 25 / Line 27 18.15% 18.15% 15.72% 12.37% 11.36% 9.72% 8.78%36 Capital Structure Adjustment Line 26 / Line 27 -2.38% -2.38% -2.27% -0.65% -2.05% -1.47% -5.28%

Note (1): The above ratios are on a ratemaking basis.Note (2): Data is presented on a 13-month average basis.


Historical and Projected Financial Metrics - Ratemaking Basis(000s)


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


* * * * *



PAUL R. MOUL

FOR


June 7, 2013

GLOSSARY OF ACRONYMS AND DEFINED TERMS

ACRONYM DEFINED TERM

AFUDC Allowance for Funds Used During Construction

β Beta

b Represents the retention rate that consists of the fraction of earnings that are not paid out as dividends

b x r Represents internal growth

CAPM Capital Asset Pricing Model

CCR Corporate Credit Rating

CE Comparable Earnings

CPFF Commercial Paper Funding Facility

DCF Discounted Cash Flow

FFO Funds from Operations

FOMC Federal Open Market Committee

g Growth rate

GSE Government-sponsored enterprises

IGF Internally Generated Funds

LDC Local Distribution Companies

Lev Leverage modification

LT Long Term

MGUC Michigan Gas Utilities Corporation

MPSC Michigan Public Service Commission

MLPs Master Limited Partnerships

P-E Price-earnings

PUC Public Utility Commission

r Represents the expected rate of return on common equity

Rf Risk-free rate of return

Rm Market risk premium

RP Risk Premium

GLOSSARY OF ACRONYMS AND DEFINED TERMS

ACRONYM DEFINED TERM

s Represents the new common shares expected to be issued by a firm

s x v Represents external growth

S&P Standard & Poor’s

v Represents the value that accrues to existing shareholders from selling stock at a price different from book value

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QUALIFICATIONS OF

PAUL R. MOUL PART I

INTRODUCTION AND SUMMARY OF RECOMMENDATIONS 1

Q. Please state your name, occupation and business address. 2

A. My name is Paul Ronald Moul. My business address is 251 Hopkins Road, 3

Haddonfield, New Jersey 08033-3062. I am Managing Consultant at the firm P. Moul 4

& Associates, an independent financial and regulatory consulting firm. My 5

educational background, business experience and qualifications are provided in 6

Appendix A, which follows my direct testimony. 7

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PAUL R. MOUL DIRECT TESTIMONY

PART II Q. What is the purpose of your pre-filed direct testimony? 1

A. My direct testimony presents evidence, analysis, and a recommendation concerning 2

the appropriate cost of equity that the Michigan Public Service Commission (“MPSC”) 3

should recognize in the determination of the revenues that Michigan Gas Utilities 4

Corporation (“MGUC” or “the Company”) should realize as a result of this proceeding. 5

My analysis and recommendation are supported by the detailed financial data 6

contained in Exhibit A-4 (PRM-1), which is divided into twelve (12) schedules. 7

8

Q. Are you the witness sponsoring Exhibit A-4 (PRM-1)? 9

A. Yes, I am. 10

11

Q. Was Exhibit A-4 (PRM-1) prepared by you or under your supervision? 12

A. Yes, it was. 13

14

Q. Based upon your analysis, what is your conclusion concerning the appropriate 15

cost of equity for the Company in this case? 16

A. My conclusion is that the Company’s cost of equity is 10.75% and that the 17

Commission should adopt this cost rate as part of its determination of the Company’s 18

rates. My cost of equity determination is part of the Company’s weighted average 19

cost of capital, which is the product of weighting the individual capital costs by the 20

proportion of each respective type of capital; should, if adopted by the Commission, 21

establish a compensatory level of return for the use of such capital; and should 22

provide the Company with the ability to attract capital on reasonable terms. The 23

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details supporting my cost of equity determination are presented on Schedule D6. 1

2

Q. What background information have you considered in reaching a conclusion 3

concerning the Company’s cost of equity? 4

A. The Company is a wholly-owned subsidiary of Integrys Energy Group, Inc. 5

("Integrys"). MGUC was acquired by Integrys on April 1, 2006 from Aquila, Inc. d/b/a 6

Aquila Networks – MGU. Integrys was formerly named WPS Resources Corporation 7

prior to its merger with Peoples Energy Corporation. The merger with Peoples 8

Energy Corporation was completed on February 21, 2007. Integrys is a holding 9

company and owns, in addition to MGUC, The Peoples Gas Light and Coke 10

Company, North Shore Gas Company, Minnesota Energy Resources Corporation, 11

Upper Peninsula Power Company, Wisconsin Public Service Corporation, and other 12

energy investments. 13

14

MGUC distributes natural gas to approximately 166,000 customers in 147 15

communities in southern and western portions of Michigan, including Grand Haven, 16

Otsego, Benton Harbor, Coldwater, and Monroe. Throughput to its customers in 2012 17

was represented by approximately 36% to residential customers, 10% to commercial 18

and small industrial customers, and 54% to transportation customers, based on 2012 19

Calendar Sales displayed on Exhibit A-15 (MMD-2), Schedule E1.1. Approximately 20

98% of MGUC’s residential customers use natural gas for space heating purposes. 21

This means that MGUC’s throughput is sensitive to temperature conditions over which 22

MGUC has absolutely no control. The Company’s throughput is also significantly 23

influenced by transportation customers, which represent 54% of total throughput, but 24

comprise just 0.1% of total customers, based on 2012 year end customers from 25

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Exhibit A-15 (MMD-2), Schedule E2. As such, the energy needs of a few customers 1

can have a significant impact on MGUC’s operations. 2

3

Q. How have you determined the cost of common equity in this case? 4

A. The cost of common equity is established using capital market and financial data 5

relied upon by investors to assess the relative risk, and hence the cost of equity, for a 6

gas distribution utility, such as the Company. In this regard, I have considered three 7

(3) well-recognized measures of the cost of equity: the Discounted Cash Flow 8

(“DCF”) model, the Risk Premium (“RP”) analysis, and the Capital Asset Pricing Model 9

(“CAPM”). I also considered as a check on the results of these models the 10

Comparable Earnings (“CE”) approach. 11

12

Q. In your opinion, what factors should the Commission consider when 13

determining the Company’s rate of return in this proceeding? 14

A. The Commission’s rate of return allowance must be set to cover the Company’s 15

interest and dividend payments, provide a reasonable level of earnings retention, 16

produce an adequate level of internally generated funds to meet capital requirements, 17

be commensurate with the risk to which the Company’s capital is exposed, assure 18

confidence in the financial integrity of the Company, support reasonable credit quality, 19

and allow the Company to raise capital on reasonable terms. The return that I 20

propose fulfills these established standards of a fair rate of return set forth by the 21

landmark Bluefield and Hope cases.1 That is to say, my proposed rate of return is 22

commensurate with returns available on investments having corresponding risks. 23

24 1Bluefield Water Works & Improvement Co. v. P.S.C. of West Virginia, 262 U.S. 679 (1923) and F.P.C. v. Hope Natural Gas Co., 320 U.S. 591 (1944).

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Q. How have you measured the cost of equity in this case? 1

A. It is necessary to use a proxy group of companies to measure the Company’s cost of 2

equity because its stock is not traded. As noted above, the Company’s stock is 3

completely owned by Integrys. The use of a proxy group to measure the Company’s 4

current cost of equity is a common practice of analysts performing these types of 5

studies. 6

7

Q. Please explain the selection process used to assemble the proxy group? 8

A. I began with the universe of gas utilities contained in the basic service of The Value 9

Line Investment Survey, which consists of eleven companies. Value Line is an 10

investment advisory service that is a widely used source in public utility rate cases. 11

Value Line is a database that is familiar to the Commission, and is widely available to 12

investors. Value Line is frequently used by utility witnesses and witnesses for the 13

Staff in public utility rate cases. I eliminated two companies from the Value Line 14

group when I assembled my proxy group. The eliminations were NiSource, Inc. due 15

to its natural gas pipeline and storage operations, and UGI Corporation because of its 16

highly diversified businesses. The remaining nine companies are included in my 17

proxy group. To this group, I added four combination gas and electric utilities that are 18

primarily delivery companies (i.e., they have no significant generation assets). The 19

complete group is comprised of the following companies: AGL Resources, Inc., 20

Atmos Energy Corp., Consolidated Edison, Inc., Laclede Group, Inc., New Jersey 21

Resources Corp., Northeast Utilities, Northwest Natural Gas, PEPCO Holdings, Inc., 22

Piedmont Natural Gas Co., South Jersey Industries, Inc., Southwest Gas Corporation, 23

UIL Holding Corporation, and WGL Holdings, Inc. I will refer to these companies as 24

the “Delivery Group” throughout my testimony. The models that I used to measure 25

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the cost of common equity for the Company were applied with market and financial 1

data developed from this group. 2

3

Q. Why have you performed your cost of equity analysis utilizing the group 4

average market data? 5

A. I have applied the models/methods for estimating the cost of equity using the average 6

data for the Delivery Group. I have not measured separately the cost of equity for the 7

individual companies within the Delivery Group, because the determination of the cost 8

of equity for an individual company can be problematic. The use of group average 9

data will reduce the effect of potentially anomalous results for an individual company if 10

a company-by-company approach were utilized. This is to say, by employing group 11

average data, rather than individual company analysis, I have minimized the effect of 12

extraneous influences on the market data for an individual company. 13

14

Q. Please summarize your cost of equity analysis. 15

A. My cost of equity determination was derived from the results of the methods/models 16

identified above. In general, the use of more than one method provides a superior 17

foundation to arrive at the cost of equity. At any point in time, any single method can 18

provide an incomplete measure of the cost of equity. The following table, derived 19

from the model results presented on Schedule D6, provides a summary of the 20

indicated costs of equity using each of these approaches. 21

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DCF 9.63%

RP 12.00%

CAPM 11.01%

Measures of Central Tendency:Average 10.88%Median 11.01%Mid-point 10.82%

Comparable Earnings 12.85%

From these results, a reasonable return on equity for the Company would be 10.75%. 1

Indeed, the midpoint of the DCF and Risk Premium results is 10.82% (9.63% + 2

12.00% = 21.63% ÷ 2) and the midpoint of the DCF and CAPM results is 10.32% 3

(9.63% + 11.01% = 20.64% ÷ 2). The 10.75% cost of equity that I propose fits well 4

within this range. As I indicated previously, the results of the Comparable Earnings 5

approach, which provides a 12.85% return, confirms the reasonableness of my cost of 6

equity determination. My recommended rate of return on common equity of 10.75% 7

makes no provision for the prospect that the rate of return may not be achieved due to 8

unforeseen events, such as unexpected spikes in the cost of purchased products and 9

other expenses. To obtain new capital and retain existing capital, the rate of return on 10

common equity must be high enough to satisfy investors’ requirements. Indeed, in a 11

study prepared for the American Gas Foundation, it was noted that allowed equity 12

returns below the level required by investors may lessen a utility’s ability to maintain 13

and develop systems that are necessary to provide natural gas service efficiently. 14

Furthermore, the report specifically found that returns below 10% would trigger broad 15

disenchantment with LDC investment. 16

17

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NATURAL GAS RISK FACTORS 1 Q. What factors currently affect the business risk of natural gas utilities? 2

A. Gas utilities face risks arising from competition, economic regulation, the business 3

cycle, and customer usage patterns. Today, they operate in a more complex 4

environment with time frames for decision-making considerably shortened. Their 5

business profile is influenced by market-oriented pricing for the commodity distributed 6

to customers and open access for the transportation of natural gas for large volume 7

customers. 8

9

Natural gas utilities have focused increased attention on safety and reliability issues. 10

In order to address these issues and to comply with new and pending pipeline safety 11

regulations, natural gas companies are now allocating more of their resources to 12

addressing aging infrastructure issues. 13

14

Q. How does the Company’s throughput to large volume customers affect its risk 15

profile? 16

A. Success in this aspect of the Company’s market is subject to the business cycle, the 17

price of alternative energy sources, and pressures from competitors. Moreover, 18

external factors can also influence the Company’s throughput to these customers, 19

which face competitive pressure on their operations from facilities located outside the 20

Company’s service territory. The Company’s risk profile is strongly influenced by 21

natural gas sold/delivered to customers engaged in manufacturing. Large volume 22

users that have traditionally used transportation service also have the ability to bypass 23

the Company’s facilities. To date, MGUC has been proactive to the threat of bypass 24

by working with its customers that are in close proximity to interstate pipelines. 25

Success in this aspect of MGUC’s market is subject to the business cycle, the price of 26

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alternative energy sources, and pressures from competitors. Moreover, external 1

factors can also influence MGUC’s throughput to these customers because cost 2

factors can impact their operations relative to alternative facilities located outside 3

MGUC’s service territory. 4

5

Q. Please indicate how its construction program affects the Company’s risk 6

profile. 7

A. The Company is required to undertake investments to maintain and upgrade existing 8

facilities in its service territories. To maintain safe and reliable service to existing 9

customers, MGUC must invest to upgrade its infrastructure. The Company projects 10

its construction expenditures will be $89 million during the period 2013-2017. Over 11

this period, these capital expenditures will represent approximately 61% ($89 million ÷ 12

$145 million) of its net utility plant at December 31, 2012. As previously noted, a fair 13

rate of return represents a key to a financial profile that will provide the Company with 14

the ability to raise the capital necessary to meet its needs on reasonable terms. 15

16

Q. Does your cost of equity analysis and recommendation take into account the 17

revenue decoupling mechanism (“RDM”) that is presently in effect for the 18

Company? 19

A. Yes. The Company’s RDM, which was approved in Case No. U-15990, is intended to 20

separate revenues from variations in sales related to usage caused by variations in 21

year-to-year weather conditions from the “normal” weather assumed in establishing 22

rates in a test year context. My cost of equity analysis that provides a 10.75% rate of 23

return on common equity takes into account the Company’s RDM. 24

25

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Q. How have you reflected the effect of the RDM in your analysis? 1

A. Most of the companies included in my Delivery Group already have tariffed weather 2

normalization mechanisms similar to the RDM and other tariff features designed to 3

stabilize revenues. Therefore my analysis already reflects the impacts of the RDM 4

and other revenue stabilization mechanisms on investor expectations through the use 5

of market-determined models. All but one of the companies in my Delivery Group 6

already has some form of revenue stabilization mechanism. The sole exception is 7

Laclede, which has a weather mitigated rate design that recovers its fixed costs more 8

evenly during the heating season. Therefore, the market prices of these companies’ 9

common equity reflect the expectations of investors related to a regulatory 10

mechanism that adjust revenues for abnormal weather and other occurrences. 11

12

In addition, the companies in my Delivery Group have other mechanisms that are 13

intended to stabilize revenue and assure recovery of the fixed costs. Many of these 14

mechanisms are intended to address the same issues as the Company’s proposed 15

rate design in this case. As such, the market prices of these companies’ common 16

stocks reflect the expectations of investors related to a regulatory mechanism that 17

adjust revenues for abnormal weather, changes in customer usage patterns, and 18

other items such as infrastructure investment. The trend in the industry is to stabilize 19

the recovery of fixed costs, which are unaffected by usage. Indeed, there has been a 20

proliferation of tracking mechanisms in the LDC business. 21

22

Q. How should the Commission respond to the issues facing the natural gas 23

utilities and, in particular, the Company? 24

A. The Commission should recognize and take into account the competitive environment 25

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and the risk it poses in the natural gas business in determining the cost of capital for 1

the Company, and provide a reasonable opportunity for the Company to actually 2

achieve its cost of capital. 3

4

FUNDAMENTAL RISK ANALYSIS 5 Q. Is it necessary to conduct a fundamental risk analysis to provide a framework 6

for a determination of a utility’s cost of equity? 7

A. Yes, it is. It is necessary to establish a company’s relative risk position within its 8

industry through a fundamental analysis of various quantitative and qualitative factors 9

that bear upon investors’ assessment of overall risk. The qualitative factors that bear 10

upon Company risk have already been discussed. The quantitative risk analysis 11

follows. For this purpose, I compared the Company to the S&P Public Utilities, an 12

industry-wide proxy consisting of various regulated businesses, and to the Delivery 13

Group. 14

15

Q. What are the components of the S&P Public Utilities? 16

A. The S&P Public Utilities is a widely recognized index that is comprised of electric 17

power and natural gas companies. These companies are identified on page 3 of 18

Schedule D9. 19

20

Q. Is knowledge of a utility's bond rating an important factor in assessing its risk 21

and cost of capital? 22

A. Yes. Knowledge of a company’s credit quality rating is important because the cost of 23

each type of capital is directly related to the associated risk of the firm. So while a 24

company’s credit quality risk is shown directly by the rating and yield on its bonds, 25

these relative risk assessments also bear upon the cost of equity. This is because a 26

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firm's cost of equity is represented by its borrowing cost plus compensation to 1

recognize the higher risk of an equity investment compared to debt. 2

3

Q. How do the bond ratings compare for the Company, the Delivery Group, and the 4

S&P Public Utilities? 5

A. Presently, the corporate credit rating (“CCR”) for Integrys is A- from Standard and 6

Poor’s Corporation (“S&P”), and the Long Term (“LT”) issuer rating is Baa1 from 7

Moody’s Investors Services (“Moody’s”). The credit quality ratings of Integrys are 8

cited here because MGUC does not have a credit rating and it obtains its long-term 9

debt from Integrys. The LT issuer rating by Moody’s and the CCR designation by 10

S&P focus upon the credit quality of the issuer of the debt, rather than upon the debt 11

obligation itself. For the Delivery Group, the average LT issuer rating is A3 by 12

Moody’s and the average CCR is A- by S&P, as displayed on page 2 of Schedule D8. 13

For the S&P Public Utilities, the average composite rating is Baa1 by Moody’s and 14

BBB+ by S&P, as displayed on page 3 of Schedule D9. Many of the financial 15

indicators that I will subsequently discuss are considered during the rating process. 16

17

Q. How do the financial data compare for the Company, the Delivery Group, and 18

the S&P Public Utilities? 19

A. The broad categories of financial data that I will discuss are shown on Schedules D7, 20

D8, and D9. The important categories of relative risk may be summarized as follows: 21

22

Size. In terms of capitalization, the Company is much smaller than the average size 23

of the Delivery Group, and very much smaller than the average size of the S&P Public 24

Utilities. All other things being equal, a smaller company is riskier than a larger 25

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company because a given change in revenue and expense has a proportionately 1

greater impact on a small firm. As I will demonstrate later, the size of a firm can 2

impact its cost of equity. This is the case for MGUC and the Delivery Group. 3

4

Market Ratios. Market-based financial ratios, such as earnings/price ratios and 5

dividend yields, provide a partial measure of the investor-required cost of equity. If all 6

other factors are equal, investors will require a higher rate of return for companies that 7

exhibit greater risk, in order to compensate for that risk. That is to say, a firm that 8

investors perceive to have higher risks will experience a lower price per share in 9

relation to expected earnings.2 10

11

There are no market ratios available for the Company because Integrys owns its 12

stock. The five-year average price-earnings multiple for the Delivery Group was 13

slightly higher than that of the S&P Public Utilities. The five-year average dividend 14

yields were somewhat lower for the Delivery Group as compared to the S&P Public 15

Utilities. The average market-to-book ratios were somewhat higher for the Delivery 16

Group as compared to the S&P Public Utilities. 17

18

Common Equity Ratio. The level of financial risk is measured by the proportion of 19

long-term debt and other senior capital that is contained in a company’s capitalization. 20

Financial risk is also analyzed by comparing common equity ratios (the complement 21

of the ratio of debt and other senior capital). That is to say, a firm with a high common 22

equity ratio has lower financial risk, while a firm with a low common equity ratio has 23

2For example, two otherwise similarly situated firms each reporting $1.00 in earnings per share would have different market prices at varying levels of risk (i.e., the firm with a higher level of risk will have a lower share value, while the firm with a lower risk profile will have a higher share value).

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higher financial risk. The five-year average common equity ratios, based on total 1

capital were 56.3% for MGUC, 47.6% for the Delivery Group, and 43.3% for the S&P 2

Public Utilities. 3

4

Return on Book Equity. Greater variability (i.e., uncertainty) of a firm’s earned returns 5

signifies relatively greater levels of risk, as shown by the coefficient of variation 6

(standard deviation ÷ mean) of the rate of return on book common equity. The higher 7

the coefficients of variation, the greater degree of variability. For the five-year period, 8

the coefficients of variation were 0.132 (0.7% ÷ 5.3%) for the Company, 0.050 (0.5% ÷ 9

10.1%) for the Delivery Group, and 0.104 (1.1% ÷ 10.6%) for the S&P Public Utilities. 10

The Company’s rates of return on equity were more variable than the Delivery Group 11

and the S&P Public Utilities. 12

13

Operating Ratios. I have also compared operating ratios (the percentage of revenues 14

consumed by operating expense, depreciation, and taxes other than income).3 The 15

five-year average operating ratios were 91.0% for the Company, 87.5% for the 16

Delivery Group, and 82.3% for the S&P Public Utilities. The Company had higher 17

operating ratios than the Delivery Group and S&P Public Utilities. 18

19

Coverage. The level of fixed charge coverage (i.e., the multiple by which available 20

earnings cover fixed charges, such as interest expense) provides an indication of the 21

earnings protection for creditors. Higher levels of coverage, and hence earnings 22

protection for fixed charges, are usually associated with superior grades of 23

creditworthiness. The five-year average interest coverage (excluding Allowance for 24 3The complement of the operating ratio is the operating margin which provides a measure of profitability. The higher the operating ratio, the lower the operating margin.

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Funds Used During Construction (“AFUDC”)) was 2.98 times for the Company, 3.99 1

times for the Delivery Group, and 3.12 times for the S&P Public Utilities. 2

3

Quality of Earnings. Measures of earnings quality usually are revealed by the 4

percentage of AFUDC related to income available for common equity, the effective 5

income tax rate, and other cost deferrals. These measures of earnings quality usually 6

influence a firm’s internally generated funds because poor quality of earnings would 7

not generate high levels of cash flow. Quality of earnings has not been a significant 8

concern for the Company, the Delivery Group and the S&P Public Utilities. 9

10

Internally Generated Funds. Internally generated funds (“IGF”) provide an important 11

source of new investment capital for a utility and represent a key measure of credit 12

strength. Historically, the five-year average percentage of IGF to capital expenditures 13

was 96.7% for MGUC, 94.1% for the Delivery Group, and 91.1% for the S&P Public 14

Utilities. 15

16

Betas. The financial data that I have been discussing relate primarily to company-17

specific risks. Market risk for firms with publicly-traded stock is measured by beta 18

coefficients. Beta coefficients attempt to identify systematic risk, i.e., the risk 19

associated with changes in the overall market for common equities.4 Value Line 20

publishes such a statistical measure of a stock’s relative historical volatility to the rest 21 4 Beta is a relative measure of the historical sensitivity of the stock’s price to overall fluctuations in the New York Stock Exchange Composite Index. The ‘‘Beta coefficient’’ is derived from a regression analysis of the relationship between weekly percentage changes in the price of a stock and weekly percentage changes in the NYSE Index over a period of five years. The betas are adjusted for their long-term tendency to converge toward 1.00. A common stock that has a beta less than 1.0 is considered to have less systematic risk than the market as a whole and would be expected to rise and fall more slowly than the rest of the market. A stock with a beta above 1.0 would have more systematic risk.

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of the market. A comparison of market risk is shown by the Value Line beta of 0.67 1

as the average for the Delivery Group (see page 2 of Schedule D8) and 0.75 as the 2

average for the S&P Public Utilities (see page 3 of Schedule D9). 3

4

Q. Please summarize your risk evaluation. 5

A. The risk of MGUC parallels that of the Delivery Group in certain respects. On some 6

counts MGUC’s risk is higher, such as its smaller size, its much higher earnings 7

variability, its higher operating ratio, and its lower interest coverage. On the other 8

hand, MGUC’s financial risk is lower as indicated by its higher common equity ratio. 9

Other measures are approximately equal, i.e., its IGF to construction and quality of 10

earnings. On balance, the Delivery Group provides a reasonable basis for measuring 11

MGUC’s cost of equity for this case, albeit a conservative measure due to MGUC’s 12

more numerous high risk factors. 13

14

DISCOUNTED CASH FLOW 15 Q. Please describe your use of the Discounted Cash Flow approach to determine 16

the cost of equity. 17

A. The DCF model seeks to explain the value of an asset as the present value of future 18

expected cash flows discounted at the appropriate risk-adjusted rate of return. In its 19

simplest form, the DCF return on common stock consists of a current cash (dividend) 20

yield and future price appreciation (growth) of the investment. The dividend discount 21

equation is the familiar DCF valuation model and assumes future dividends are 22

systematically related to one another by a constant growth rate. The DCF formula is 23

derived from the standard valuation model: P = D/(k-g), where P = price, D = 24

dividend, k = the cost of equity, and g = growth in cash flows. By rearranging the 25

terms, we obtain the familiar DCF equation: k= D/P + g. All of the terms in the DCF 26

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equation represent investors’ assessment of expected future cash flows that they will 1

receive in relation to the value that they set for a share of stock (P). The DCF 2

equation is sometimes referred to as the "Gordon" model.5 My DCF results are 3

provided on Schedule D6 for the Delivery Group. The DCF return is 9.63%. 4

5

Among other limitations of the model, there is a certain element of circularity in the 6

DCF method when applied in rate cases. This is because investors’ expectations for 7

the future depend upon regulatory decisions. In turn, when regulators depend upon 8

the DCF model to set the cost of equity, they rely upon investor expectations that 9

include an assessment of how regulators will decide rate cases. Due to this 10

circularity, the DCF model may not fully reflect the true risk of a utility. 11

12

Q. Please explain the dividend yield component of a DCF analysis. 13

A. The DCF methodology requires the use of an expected dividend yield to establish the 14

investor-required cost of equity. The monthly dividend yields for the twelve months 15

ended December 2012 are shown on Schedule D10 and capture an adjustment to the 16

month-end prices to reflect the buildup of the dividend in the price that has occurred 17

since the last ex-dividend date (i.e., the date by which a shareholder must own the 18

shares to be entitled to the dividend payment – usually about two to three weeks prior 19

to the actual payment). 20

21

For the twelve months ended December 2012, the average dividend yield was 4.02% 22

for the Delivery Group based upon a calculation using annualized dividend payments 23

5Although the popular application of the DCF model is often attributed to the work of Myron J. Gordon in the mid-1950’s, J. B. Williams exposited the DCF model in its present form nearly two decades earlier.

-18-

and adjusted month-end stock prices. The dividend yields for the more recent six- 1

and three-month periods were 4.02% and 4.09%, respectively. I have used, for the 2

purpose of the DCF model, the six-month average dividend yield of 4.02% for the 3

Delivery Group. The use of this dividend yield will reflect current capital costs, while 4

avoiding spot yields. For the purpose of a DCF calculation, the average dividend yield 5

must be adjusted to reflect the prospective nature of the dividend payments, i.e., the 6

higher expected dividends for the future. Recall that the DCF is an expectational 7

model that must reflect investor anticipated cash flows for the Delivery Group. I have 8

adjusted the six-month average dividend yield in three different, but generally 9

accepted, manners and used the average of the three adjusted values as calculated 10

in the lower panel of data presented on Schedule D10. That adjusted dividend yield is 11

4.13% for the Delivery Group. 12

13

Q. Please explain the underlying factors that influence investor’s growth 14

expectations. 15

A. As noted previously, investors are interested principally in the future growth of their 16

investment (i.e., the price per share of the stock). Future earnings per share growth 17

represent the DCF model’s primary focus because under the constant price-earnings 18

multiple assumption of the model, the price per share of stock will grow at the same 19

rate as earnings per share. In conducting a growth rate analysis, a wide variety of 20

variables can be considered when reaching a consensus of prospective growth, 21

including: earnings, dividends, book value, and cash flow stated on a per share basis. 22

Historical values for these variables can be considered, as well as analysts’ forecasts 23

that are widely available to investors. A fundamental growth rate analysis is 24

sometimes represented by the internal growth (“b x r”), where “r” represents the 25

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expected rate of return on common equity and “b” is the retention rate that consists of 1

the fraction of earnings that are not paid out as dividends. To be complete, the 2

internal growth rate should be modified to account for sales of new common stock -- 3

this is called external growth (“s x v”), where “s” represents the new common shares 4

expected to be issued by a firm and “v” represents the value that accrues to existing 5

shareholders from selling stock at a price different from book value. Fundamental 6

growth, which combines internal and external growth, provides an explanation of the 7

factors that cause book value per share to grow over time. 8

9

Growth also can be expressed in multiple stages. This expression of growth consists 10

of an initial “growth” stage where a firm enjoys rapidly expanding markets, high profit 11

margins, and abnormally high growth in earnings per share. Thereafter, a firm enters 12

a “transition” stage where fewer technological advances and increased product 13

saturation begin to reduce the growth rate and profit margins come under pressure. 14

During the “transition” phase, investment opportunities begin to mature, capital 15

requirements decline, and a firm begins to pay out a larger percentage of earnings to 16

shareholders. Finally, the mature or “steady-state” stage is reached when a firm’s 17

earnings growth, payout ratio, and return on equity stabilizes at levels where they 18

remain for the life of a firm. The three stages of growth assume a step-down of high 19

initial growth to lower sustainable growth. Even if these three stages of growth can be 20

envisioned for a firm, the third “steady-state” growth stage, which is assumed to 21

remain fixed in perpetuity, represents an unrealistic expectation because the three 22

stages of growth can be repeated. That is to say, the stages can be repeated where 23

growth for a firm ramps-up and ramps-down in cycles over time. 24

25

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Q. What investor-expected growth rate is appropriate in a DCF calculation? 1

A. Investors consider both company-specific variables and overall market sentiment (i.e., 2

level of inflation rates, interest rates, economic conditions, etc.) when balancing their 3

capital gains expectations with their dividend yield requirements. I follow an approach 4

that is not rigidly formatted because investors are not influenced by a single set of 5

company-specific variables weighted in a formulaic manner. Therefore, in my opinion, 6

all relevant growth rate indicators using a variety of techniques must be evaluated 7

when formulating a judgment of investor-expected growth. 8

9

Q. What data for the proxy group have you considered in your growth rate 10

analysis? 11

A. I have considered the growth in the financial variables shown on Schedules D11 and 12

D12. The historical growth rates were taken from the Value Line publication that 13

provides these data. As shown on Schedule D11, the historical growth of earnings 14

per share was in the range of 4.33% to 5.35% for the Delivery Group. 15

16

Schedule D12 provides projected earnings per share growth rates taken from 17

analysts’ forecasts compiled by IBES/First Call, Zacks, Morningstar, and Value Line. 18

IBES/First Call, Zacks, and Morningstar represent reliable authorities of projected 19

growth upon which investors rely. The IBES/First Call and Zacks growth rates are 20

consensus forecasts taken from a survey of analysts that make projections of growth 21

for these companies. The IBES/First Call, Zacks, and Morningstar estimates are 22

obtained from the Internet and are widely available to investors. First Call probably is 23

quoted most frequently in the financial press when reporting on earnings forecasts. 24

The Value Line forecasts also are widely available to investors and can be obtained 25

-21-

by subscription or free-of-charge at most public and collegiate libraries. The 1

IBES/First Call, Zacks, and Morningstar forecasts are limited to earnings per share 2

growth, while Value Line makes projections of other financial variables. The Value 3

Line forecasts of dividends per share, book value per share, and cash flow per share 4

have also been included on Schedule D12 for the Delivery Group. 5

6

Q. What specific evidence have you considered in the DCF growth analysis? 7

A. As to the five-year forecast growth rates, Schedule D12 indicates that the projected 8

earnings per share growth rates for the Delivery Group are 4.69% by IBES/First Call, 9

4.65% by Zacks, 4.97% by Morningstar, and 5.19% by Value Line. The Value Line 10

projections indicate that earnings per share for the Delivery Group will grow 11

prospectively at a more rapid rate (i.e., 5.19%) than the dividends per share (i.e., 12

3.79%), which translates into a declining dividend payout ratio for the future. As noted 13

earlier, with the constant price-earnings multiple assumption of the DCF model, 14

growth for these companies will occur at the higher earnings per share growth rate, 15

thus producing the capital gains yield expected by investors. 16

17

Q. What conclusion have you drawn from these data regarding the applicable 18

growth rate to be used in the DCF model? 19

A. A variety of factors should be examined to reach a conclusion on the DCF growth 20

rate. However, certain growth rate variables should be emphasized when reaching a 21

conclusion on an appropriate growth rate. First, historical and projected earnings per 22

share, dividends per share, book value per share, cash flow per share, and retention 23

growth represent indicators that could be used to provide an assessment of investor 24

growth expectations for a firm. However, although history cannot be ignored, it 25

-22-

cannot receive primary emphasis. This is because an analyst, when developing a 1

forecast of future earnings growth, would first apprise himself/herself of the historical 2

performance of a company. Hence, there is no need to count historical growth rates 3

separately, because historical performance already is reflected in analysts’ forecasts. 4

Second, from the various alternative measures of growth identified above, earnings 5

per share should receive greatest emphasis. Earnings per share growth is the 6

primary determinant of investors’ expectations regarding their total returns in the stock 7

market. This is because the capital gains yield (i.e., price appreciation) will track 8

earnings growth with a constant price earnings multiple (a key assumption of the DCF 9

model). Moreover, earnings per share (derived from net income) are the source of 10

dividend payments, and are the primary driver of retention growth and its surrogate, 11

i.e., book value per share growth. As such, under these circumstances, greater 12

emphasis must be placed upon projected earnings per share growth. In this regard, it 13

is worthwhile to note that Professor Myron Gordon, the foremost proponent of the 14

DCF model in rate cases, concluded that the best measure of growth in the DCF 15

model is a forecast of earnings per share growth.6 Hence, to follow Professor 16

Gordon’s findings, projections of earnings per share growth, such as those published 17

by IBES/First Call, Zacks, Morningstar, and Value Line, represent a reasonable 18

assessment of investor expectations. 19

20

The forecasts of earnings per share growth, as shown on Schedule D12, provide a 21

range of average growth rates of 4.65% to 5.19%. Although the DCF growth rates 22

cannot be established solely with a mathematical formulation, it is my opinion that an 23

investor-expected growth rate of 5.00% is within the array of earnings per share 24 6Gordon, Gordon & Gould ,“Choice Among Methods of Estimating Share Yield,” The Journal of Portfolio Management (Spring 1989).

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growth rates shown by the analysts’ forecasts. While the growth rate that I 1

determined for the DCF analysis is higher than the midpoint of the range noted above, 2

it is reflective of growth that is associated with improving business conditions. The 3

stellar performance of the stock market in 2013 points to an improving economy, as it 4

is one of the leading economic indicators compiled by The Conference Board.7 In 5

fact, the Leading Economic Index, whose financial components include the stock 6

market, has increased in five of the last six months. In addition, “the strengths among 7

the leading indicators have become more widespread in recent months,” said The 8

Conference Board. 9

10

Q. Are the dividend yield and growth components of the DCF adequate to explain 11

the rate of return on common equity when it is used in the calculation of the 12

weighted average cost of capital? 13

A. Only if the capital structure ratios are measured with the market value of debt and 14

equity. In the case of the Delivery Group, those average capital structure ratios are 15

39.03% long-term debt, 0.20% preferred stock, and 60.77% common equity, as 16

shown on Schedule D13. If book values are used to compute the capital structure 17

ratios, then an adjustment is required. 18

19

Q. Please explain why. 20

A. If regulators use the results of the DCF (which are based on the market price of the 21

stock of the companies analyzed) to compute the weighted average cost of capital 22

based on a book value capital structure used for ratesetting purposes, the utility will 23

7 The Conference Board U.S. Business Cycle Indicators -The Conference Board Leading Economic Index (LEI) for the U.S. and Related Composite Economic Indexes for February 2013 [Press Release]. Retrieved from http://www.conference-board.org/data/bci.cfm dated March 21, 2013

http://www.conference-board.org/data/bci.cfm

-24-

not, by definition, recover its risk-adjusted capital cost. This is because market 1

valuations of equity are based on market value capital structures, which in general 2

have more equity and less debt and therefore reflect less risk than book value capital 3

structures (see Schedule D13 for the comparison). The utility’s risk-adjusted cost of 4

equity will necessarily be lower with the less risky market value capital structure than 5

with the book value capital structure. The difference represents that portion of the 6

utility’s cost of equity that it will not recover unless either the market value cost of 7

equity is applied to the utility’s market value capital structure or it is adjusted to reflect 8

the higher risk associated with the book value capital structure. By the same token, if 9

the utility’s market value capital structure is less than its book value structure, then the 10

utility’s market cost of equity should be adjusted downward to reflect the lower risk 11

associated with the book value capital structure, or else the utility will over-recover its 12

total cost of equity. 13

14

This shortcoming of the DCF has persuaded the Pennsylvania Public Utility 15

Commission to adjust the DCF determined cost of equity upward to make the return 16

consistent with the book value capital structure. Specific adjustments to recognize 17

this risk difference were made in the following cases: 18

• January 10, 2002 for Pennsylvania-American Water Company in Docket No. R-19 00016339 -- 60 basis points adjustment. 20

21 • August 1, 2002 for Philadelphia Suburban Water Company in Docket No. R-22

00016750 -- 80 basis points adjustment. 23 24 • January 29, 2004 for Pennsylvania-American Water Company in Docket No. 25

R-00038304 (affirmed by the Commonwealth Court on November 8, 2004) -- 60 26 basis points adjustment. 27

28 • August 5, 2004 for Aqua Pennsylvania, Inc. in Docket No. R-00038805 -- 60 29

basis points adjustment. 30 31 • December 22, 2004 for PPL Electric Utilities Corporation in Docket No. R-32

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00049255 -- 45 basis points adjustment. 1 2 • February 8, 2007 for PPL Gas Utilities Corporation in Docket No. R-00061398 -- 3

70 basis points adjustment. 4 5

In order to make the DCF results relevant to the capitalization measured at book 6

value (as is done for rate setting purposes), the market-derived cost rate cannot be 7

used without modification. 8

9

Q. Is your leverage adjustment dependent upon the market valuation or book 10

valuation from an investor’s perspective? 11

A. The only perspective that is important to investors is the return that they can realize 12

on the market value of their investment. As I have measured the DCF, the simple 13

yield (D/P) plus growth (g) provides a return applicable strictly to the price (P) that an 14

investor is willing to pay for a share of stock. The need for the leverage adjustment 15

arises when the results of the DCF model (k) are to be applied to a capital structure 16

that is different than indicated by the market price (P). From the market perspective, 17

the financial risk of the Delivery Group is accurately measured by the capital structure 18

ratios calculated from the market capitalization of a firm. If the ratesetting process 19

utilized the market capitalization ratios, then no additional analysis or adjustment 20

would be required, and the simple yield (D/P) plus growth (g) components of the DCF 21

would satisfy the financial risk associated with the market value of the equity 22

capitalization. Because the ratesetting process uses a different set of ratios 23

calculated from the book value capitalization, then further analysis is required to 24

synchronize the financial risk of the book capitalization with the required return on the 25

book value of the equity. This adjustment is developed through precise mathematical 26

calculations, using well recognized analytical procedures that are widely accepted in 27

the financial literature. To arrive at that return, the rate of return on common equity is 28

-26-

the unleveraged cost of capital (or equity return at 100% equity) plus one or more 1

terms reflecting the increase in financial risk resulting from the use of leverage in the 2

capital structure. The calculations presented in the lower panel of data shown on 3

Schedule D13, under the heading “M&M,” provides a return of 7.59% when applicable 4

to a capital structure with 100% common equity. 5

6

Q. How is the DCF-determined cost of equity adjusted for the financial risk 7

associated with the book value of the capitalization? 8

A. In pioneering work, Nobel laureates Modigliani and Miller developed several theories 9

about the role of leverage in a firm's capital structure. As part of that work, Modigliani 10

and Miller established that, as the borrowing of a firm increases, the expected return 11

on stockholders' equity also increases. This principle is incorporated into my leverage 12

adjustment, which recognizes that the expected return on equity increases to reflect 13

the increased risk associated with the higher financial leverage shown by the book 14

value capital structure, as compared to the market value capital structure that 15

contains lower financial risk. Modigliani and Miller proposed several approaches to 16

quantify the equity return associated with various degrees of debt leverage in a firm's 17

capital structure. These formulas point toward an increase in the equity return 18

associated with the higher financial risk of the book value capital structure. Simply 19

stated, the leverage adjustment contains no factor for a particular market-to-book 20

ratio. It merely expresses the cost of equity as the unleveraged return plus 21

compensation for the additional risk of introducing debt and/or preferred stock into the 22

capital structure. There can be no dispute that a firm’s financial risk varies with the 23

relative amount of leverage contained in its capital structure. 24

25

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Q. Is the leverage adjustment that you propose designed to transform the market 1

return into one that is designed to produce a particular market-to-book ratio? 2

A. No, it is not. The adjustment that I label as a “leverage adjustment” is merely a 3

convenient way of showing the amount that must be added to (or subtracted from) the 4

result of the simple DCF model (i.e., D/P + g), in the context of a return that applies to 5

the capital structure used in ratemaking, which is computed with book value weights 6

rather than market value weights, in order to arrive at the utility’s total cost of equity. I 7

specify a separate factor, which I call the leverage adjustment, but there is no need to 8

do so other than providing identification for this factor. If I expressed my return solely 9

in the context of the book value weights that we use to calculate the weighted average 10

cost of capital, and ignore the familiar D/P + g expression entirely, then there would 11

be no separate element to reflect the financial leverage change from market value to 12

book value capitalization. As shown in the bottom panel of data on Schedule D13, the 13

equity return applicable to the book value common equity ratio is equal to 7.59%, 14

which is the return for the Delivery Group applicable to its equity with no debt in its 15

capital structure (i.e., the cost of capital is equal to the cost of equity with a 100% 16

equity ratio) plus 2.03% compensation for having a 46.60% debt ratio, plus 0.01% for 17

having a 0.29% preferred stock ratio. The sum of the parts is 9.63% (7.59% + 2.03% 18

+ 0.01%) and there is no need to even address the cost of equity in terms of D/P + g. 19

To express this same return in the context of the familiar DCF model, I summed the 20

4.13% dividend yield, the 5.00% growth rate, and the 0.50% for the leverage 21

adjustment in order to arrive at the same 9.63% (4.13% + 5.00% + 0.50%) return. I 22

know of no means to mathematically solve for the 0.50% leverage adjustment by 23

expressing it in the terms of any particular relationship of market price to book value. 24

The 0.50% adjustment is merely a convenient way to compare the 9.63% return 25

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computed directly with the Modigliani & Miller formulas to the 9.13% return generated 1

by the DCF model based on a market value capital structure. My point is that when 2

we use a market-determined cost of equity developed from the DCF model, it reflects 3

a level of financial risk that is different (in this case, lower) from the capital structure 4

stated at book value. This process has nothing to do with targeting any particular 5

market-to-book ratio. Each of the calculations that I describe above apply to the 6

market returns associated with the holding companies from which the DCF is derived. 7

It is well understood that the leverage employed by the utility subsidiaries of those 8

holding companies is reflective of the risks associated with the utility business. 9

10

RISK PREMIUM ANALYSIS 11 Q. Please describe your use of the risk premium approach to determine the cost of 12

equity. 13

A. With the Risk Premium approach, the cost of equity capital is determined by corporate 14

bond yields plus a premium to account for the fact that common equity is exposed to 15

greater investment risk than debt capital. The result of my Risk Premium study is 16

shown on Schedule D6. That result is 12.00%. As with other models used to 17

determine the cost of equity, the Risk Premium approach has its limitations, including 18

potential imprecision in the assessment of the future cost of corporate debt and the 19

measurement of the risk-adjusted common equity premium. 20

21

Q. What long-term public utility debt cost rate did you use in your risk premium 22

analysis? 23

A. In my opinion, a 5.00% yield represents a reasonable estimate of the prospective 24

yield on long-term A-rated public utility bonds. 25

26

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Q. What forecasts of interest rates have you considered in your analysis? 1

A. I have determined the prospective yield on A-rated public utility debt by using the Blue 2

Chip Financial Forecasts (“Blue Chip”) along with the spread in the yields that I 3

describe below. The Blue Chip is a reliable authority and contains consensus 4

forecasts of a variety of interest rates compiled from a panel of banking, brokerage, 5

and investment advisory services. In early 1999, Blue Chip stopped publishing 6

forecasts of yields on A-rated public utility bonds because the Federal Reserve 7

deleted these yields from its Statistical Release H.15. To independently project a 8

forecast of the yields on A-rated public utility bonds, I have combined the forecast 9

yields on long-term Treasury bonds published on January 1, 2013, and a yield spread 10

of 1.50%, derived from historical data. 11

12

Q. What historical data have you analyzed? 13

A. I have analyzed the historical yields on the Moody’s index of long-term public utility 14

debt as shown on page 1 of Schedule D14. For the twelve months ended December 15

2012, the average monthly yield on Moody’s index of A-rated public utility bonds was 16

4.13%. For the six and three-month periods ended December 2012, the yields were 17

3.95% and 3.92%, respectively. During the twelve-months ended December 2012, 18

the range of the yields on A-rated public utility bonds was 3.84% to 4.48%. Page 2 of 19

Schedule D14 shows the long-run spread in yields between A-rated public utility 20

bonds and long-term Treasury bonds. As shown on page 3 of Schedule D14, the 21

yields on A-rated public utility bonds have exceeded those on Treasury bonds by 22

1.59% on a twelve-month average basis, 1.54% on a six-month average basis, and 23

1.46% on a the three-month average basis. From these averages, 1.50% represents 24

a reasonable spread for the yield on A-rated public utility bonds over Treasury bonds. 25

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1

Q. How have you used these data to project the yield on A-rated public utility 2

bonds for the purpose of your Risk Premium analyses? 3

A. Shown below is my calculation of the prospective yield on A-rated public utility bonds 4

using the building blocks discussed above, i.e., the Blue Chip forecast of Treasury 5

bond yields and the public utility bond yield spread. For comparative purposes, I also 6

have shown the Blue Chip forecasts of Aaa-rated and Baa-rated corporate bonds. 7

These forecasts are: 8

30-YearYear Quarter Aaa-rated Baa-rated Treasury Spread Yield2013 First 3.7% 4.8% 2.9% 1.50% 4.40%2013 Second 3.8% 4.9% 3.0% 1.50% 4.50%2013 Third 3.9% 4.9% 3.1% 1.50% 4.60%2013 Fourth 3.9% 5.0% 3.2% 1.50% 4.70%2014 First 4.0% 5.1% 3.3% 1.50% 4.80%2014 Second 4.1% 5.2% 3.4% 1.50% 4.90%

CorporateBlue Chip Financial Forecasts

A-rated Public Utility

Q. Are there additional forecasts of interest rates that extend beyond those shown 9

above? 10

A. Yes. Twice yearly, Blue Chip provides long-term forecasts of interest rates. In its 11

December 1, 2012 publication, Blue Chip published longer-term forecasts of interest 12

rates, which were reported to be: 13

30-YearAverages Treasury Aaa-rated Baa-rated2014-18 4.7% 5.4% 6.4%2019-23 5.5% 6.1% 7.1%

CorporateBlue Chip Financial Forecasts

Given these forecasted interest rates, a 5.00% yield on A-rated public utility bonds 14

represents a reasonable expectation. 15

-31-

1

Q. What equity risk premium have you determined for this case? 2

A. To develop an appropriate equity risk premium, I analyzed the results from the 2013 3

Classic Yearbook for Stocks, Bonds, Bills and Inflation (“SBBI”) published by Ibbotson 4

Associates that is part of Morningstar. My investigation reveals that the equity risk 5

premium varies according to the level of interest rates. That is to say, the equity risk 6

premium increases as interest rates decline and it declines as interest rates increase. 7

This inverse relationship is revealed by the summary data presented below and 8

shown on page 1 of Schedule D15. 9

Low Interest Rates 7.00%

Average Across All Interest Rates 5.41%

High Interest Rates 3.77%

Common Equity Risk Premiums

10

11

Based on my analysis of the historical data, the equity risk premium was 7.00% when 12

the marginal cost of long-term government bonds was low (i.e., 3.03%, which was the 13

average yield during periods of low rates). Conversely, when the yield on long-term 14

government bonds was high (i.e., 7.35% on average during periods of high interest 15

rates) the spread narrowed to 3.77%. Over the entire spectrum of interest rates, the 16

equity risk premium was 5.41% when the average government bond yield was 5.16%. 17

With the current low interest rates, an equity risk premium of 7.00% is indicated today. 18

19

CAPITAL ASSET PRICING MODEL 20 Q. What are the features of the CAPM as you have used it? 21

A. The CAPM uses the yield on a risk-free interest bearing obligation plus a rate of return 22

-32-

premium that is proportional to the systematic risk of an investment. The result of the 1

CAPM is 11.01% as shown on Schedule D6. To compute the cost of equity with the 2

CAPM, three components are necessary: a risk-free rate of return (“Rf”), the beta 3

measure of systematic risk (“β”), and the market risk premium (“Rm-Rf”) derived from 4

the total return on the market of equities reduced by the risk-free rate of return. The 5

CAPM specifically accounts for differences in systematic risk (i.e., market risk as 6

measured by the beta) between an individual firm or group of firms and the entire 7

market of equities. 8

9

Q. What betas have you considered in the CAPM? 10

A. For my CAPM analysis, I initially considered the Value Line betas. As shown on 11

Schedule D13, the average beta is 0.67 for the Delivery Group. 12

13

Q. What betas have you used in the CAPM determined cost of equity? 14

A. The betas must be reflective of the financial risk associated with the ratesetting capital 15

structure that is measured at book value. Therefore, Value Line betas cannot be used 16

directly in the CAPM, unless the cost rate developed using those betas is applied to a 17

capital structure measured with market values. To develop a CAPM cost rate 18

applicable to a book-value capital structure, the Value Line (market value) betas have 19

been unleveraged and releveraged for the book value common equity ratios using the 20

Hamada formula,8 as follows: 21

βl = βu [1 + (1 - t) D/E + P/E] 22

where ßl = the leveraged beta, ßu = the unleveraged beta, t = income tax rate, D = 23

8Robert S. Hamada, “The Effects of the Firm’s Capital Structure on the Systematic Risk of Common Stocks” The Journal of Finance Vol. 27, No. 2, Papers and Proceedings of the Thirtieth Annual Meeting of the American Finance Association, New Orleans, Louisiana, December 27-29, 1971. (May 1972), pp.435-452

-33-

debt ratio, P = preferred stock ratio, and E = common equity ratio. The betas 1

published by Value Line have been calculated with the market price of stock and, 2

therefore, are related to the market value capitalization. By using the formula shown 3

above and the capital structure ratios measured at market value, the beta would 4

become 0.47 for the Delivery Group if it employed no leverage and was 100% equity 5

financed. Those calculations are shown on Schedule D13 under the category 6

“Hamada” who is credited with developing those formulas. With the unleveraged beta 7

as a base, I calculated the leveraged beta of 0.73 for the book value capital structure 8

of the Delivery Group. The book value leveraged beta that I will employ in the CAPM 9

cost of equity is 0.73 for the Delivery Group. 10

11

Q. What risk-free rate have you used in the CAPM? 12

A. As shown on page 1 of Schedule D16, I provided the historical yields on Treasury 13

notes and bonds. For the twelve months ended December 2012, the average yield on 14

30-year Treasury bonds was 2.92%. For the six- and three-months ended December 15

2012, the yields on 30-year Treasury bonds were 2.80% and 2.86%, respectively. 16

During the twelve-months ended December 2012, the range of the yields on 30-year 17

Treasury bonds was 2.59% to 3.28%. The recent low yields on Treasury bonds can 18

be traced to events that have occurred during the past several years that included the 19

financial crisis and its aftermath. The resulting decline in the yields on Treasury 20

obligations can be attributed to a number of factors, including: the sovereign debt 21

crisis in the euro zone, concern over a possible double dip recession, the potential for 22

deflation, and the Federal Reserve’s large balance sheet that has been expanded 23

through the purchase of Treasury obligations and mortgage-backed securities (also 24

known as QEI, QEII, and QEIII), and the reinvestment of the proceeds from maturing 25

-34-

obligations and the lengthening of the maturity of the Fed’s bond portfolio through the 1

sale of short-term Treasuries and the purchase of long-term Treasury obligations 2

(also known as “operation twist”). Essentially, low interest rates are the product of the 3

policy of the FOMC in its attempt to deal with stagnant job growth, which is part of its 4

dual mandate. As shown on page 2 of Schedule D16, forecasts published by Blue 5

Chip on February 1, 2013 indicate that the yields on long-term Treasury bonds are 6

expected to be in the range of 2.9% to 3.4% during the next six quarters. The longer 7

term forecasts described previously show that the yields on 30-year Treasury bonds 8

will average 4.7% from 2014 through 2018 and 5.5% from 2019 to 2023. For the 9

reasons explained previously, forecasts of interest rates should be emphasized at this 10

time in selecting the risk-free rate of return in CAPM. Hence, I have used a 3.50% 11

risk-free rate of return for CAPM purposes, which considers not only the Blue Chip 12

forecasts, but also the recent trend in the yields on long-term Treasury bonds. 13

14

Q. What market premium have you used in the CAPM? 15

A. As shown in the lower panel of data presented on page 2 of Schedule D16, the 16

market premium is derived from historical data and the Value Line and S&P 500 17

returns. For the historically based market premium, I have used the arithmetic mean 18

obtained from the data presented on page 1 of Schedule D15. On that schedule, the 19

market return on large stocks during periods of low interest rates was 11.72%. During 20

that time, the yield on long-term government bonds was 3.03%. The resulting market 21

premium is 8.69% (11.72% - 3.03%) based on historical data. For the forecast 22

returns, I calculated a 12.87% total market return from the Value Line data and a DCF 23

return of 11.76% for the S&P 500. With the average forecast return of 12.32% 24

(12.87% + 11.76% = 24.63% ÷ 2), I calculated a market premium of 8.82% (12.32% - 25

-35-

3.50%) using forecast data. The market premium applicable to the CAPM derived 1

from these sources equals 8.76% (8.82% + 8.69% = 17.51% ÷ 2). 2

3

Q. Are there adjustments to the CAPM that are necessary to fully reflect the rate of 4

return on common equity? 5

A. Yes. The technical literature supports an adjustment relating to the size of the 6

company or portfolio for which the calculation is performed. As the size of a firm 7

decreases, its risk and, hence, its required return increases. Moreover, in his 8

discussion of the cost of capital, Professor Brigham has indicated that smaller firms 9

have higher capital costs than otherwise similar larger firms (see Fundamentals of 10

Financial Management, fifth edition, page 623). Also, the Fama/French study (see 11

"The Cross-Section of Expected Stock Returns"; The Journal of Finance, June 1992) 12

established that the size of a firm helps explain stock returns. In an October 15, 1995 13

article in Public Utility Fortnightly, entitled “Equity and the Small-Stock Effect,” it was 14

demonstrated that the CAPM could understate the cost of equity significantly 15

according to a company’s size. Indeed, it was demonstrated in the SBBI Yearbook 16

that the returns for stocks in lower deciles (i.e., smaller stocks) had returns in excess 17

of those shown by the simple CAPM. In this regard, the Delivery Group has a market-18

based average equity capitalization of $4,106 million, as shown on Schedule D13. 19

For my CAPM analysis, I have adopted the mid-cap adjustment of 1.12%, as revealed 20

on page 3 of Schedule D16. 21

22

COMPARABLE EARNINGS 23 Q. How have you applied the Comparable Earnings approach in this case? 24

A. The Comparable Earnings approach determines the equity return based upon results 25

from non-regulated companies. It is the oldest of all rate of return methods, having 26

-36-

been around for about one-century. Because regulation is a substitute for 1

competitively determined prices, the returns realized by non-regulated firms with 2

comparable risks to a public utility provide useful insight into a fair rate of return. In 3

order to identify the appropriate return, it is necessary to analyze returns earned (or 4

realized) by other firms within the context of the Comparable Earnings standard. The 5

firms selected for the Comparable Earnings approach should be companies whose 6

prices are not subject to cost-based price ceilings (i.e., non-regulated firms) so that 7

circularity is avoided. 8

9

There are two avenues available to implement the Comparable Earnings approach. 10

One method involves the selection of another industry (or industries) with comparable 11

risks to the public utility in question, and the results for all companies within that 12

industry serve as a benchmark. The second approach requires the selection of 13

parameters that represent similar risk traits for the public utility and the comparable 14

risk companies. Using this approach, the business lines of the comparable 15

companies become unimportant. The latter approach is preferable with the further 16

qualification that the comparable risk companies exclude regulated firms in order to 17

avoid the circular reasoning implicit in the use of the achieved earnings/book ratios of 18

other regulated firms. The United States Supreme Court has held that: 19

A public utility is entitled to such rates as will permit it to earn a 20 return on the value of the property which it employs for the 21 convenience of the public equal to that generally being made 22 at the same time and in the same general part of the country 23 on investments in other business undertakings which are 24 attended by corresponding risks and uncertainties…. The 25 return should be reasonably sufficient to assure confidence in 26 the financial soundness of the utility and should be adequate, 27 under efficient and economical management, to maintain and 28 support its credit and enable it to raise the money necessary 29 for the proper discharge of its public duties. Bluefield Water 30 Works vs. Public Service Commission, 262 U.S. 668 (1923). 31

-37-

1

Therefore, it is important to identify the returns earned by firms that compete for 2

capital with a public utility. This can be accomplished by analyzing the returns of non-3

regulated firms that are subject to the competitive forces of the marketplace. 4

5

Q. How have you implemented the Comparable Earnings approach? 6

A. In order to implement the Comparable Earnings approach, non-regulated companies 7

were selected from The Value Line Investment Survey for Windows that have six 8

categories of comparability designed to reflect the risk of the Delivery Group. These 9

screening criteria were based upon the range as defined by the rankings of the 10

companies in the Delivery Group. The items considered were: Timeliness Rank, 11

Safety Rank, Financial Strength, Price Stability, Value Line betas, and Technical 12

Rank. The identities of the companies comprising the Comparable Earnings group 13

and their associated rankings within the ranges are identified on page 1 of Schedule 14

D17. 15

16

Value Line data was relied upon because it provides a comprehensive basis for 17

evaluating the risks of the comparable firms. As to the returns calculated by Value 18

Line for these companies, there is some downward bias in the figures shown on page 19

2 of Schedule D17, because Value Line computes the returns on year-end rather than 20

average book value. If average book values had been employed, the rates of return 21

would have been slightly higher. Nevertheless, these are the returns considered by 22

investors when taking positions in these stocks. Because many of the comparability 23

factors, as well as the published returns, are used by investors in selecting stocks, 24

and the fact that investors rely on the Value Line service to gauge returns, it is, 25

-38-

therefore, an appropriate database for measuring comparable return opportunities. 1

2

Q. What data have you used in your Comparable Earnings analysis? 3

A. I have used both historical realized returns and forecasted returns for non-utility 4

companies. As noted previously, I have not used returns for utility companies in order 5

to avoid the circularity that arises from using regulatory-influenced returns to 6

determine a regulated return. It is appropriate to consider a relatively long 7

measurement period in the Comparable Earnings approach in order to cover 8

conditions over an entire business cycle. A ten-year period (five historical years and 9

five projected years) is sufficient to cover an average business cycle. Unlike the DCF 10

and CAPM, the results of the Comparable Earnings method can be applied directly to 11

the book value capitalization. In other words, the Comparable Earnings approach 12

does not contain the potential misspecification contained in market models when the 13

market capitalization and book value capitalization diverge significantly. The historical 14

rate of return on book common equity was 12.4% using only the returns that were less 15

than 20% as shown on page 2 of Schedule D17. The forecast rates of return as 16

published by Value Line are shown by the 13.3% also using values less than 20%, as 17

provided on page 2 of Schedule D17. Using these data my Comparable Earnings 18

result is 12.85%, as shown on Schedule D6. 19

20

CONCLUSION ON COST OF EQUITY 21 Q. What is your conclusion regarding the Company’s cost of common equity? 22

A. Based upon the application of a variety of methods and models described previously, 23

it is my opinion that a reasonable cost of common equity for the Company is 10.75%. 24

My cost of equity recommendation is obtained from a range of results and should be 25

considered in the context of the Company’s risk characteristics, as well as the general 26

-39-

condition of the capital markets. It is essential that the Commission employ a variety 1

of techniques to measure the Company’s cost of equity because of the 2

limitations/infirmities that are inherent in each method. 3

4


A. Yes. However, I reserve the right to supplement my testimony, if necessary, and to 6

respond to witnesses presented by other parties. 7

APPENDIX A TO DIRECT TESTIMONY OF PAUL R. MOUL

A-1

EDUCATIONAL BACKGROUND, BUSINESS EXPERIENCE 1 AND QUALIFICATIONS 2 I was awarded a degree of Bachelor of Science in Business Administration by 3

Drexel University in 1971. While at Drexel, I participated in the Cooperative Education 4

Program which included employment, for one year, with American Water Works Service 5

Company, Inc., as an internal auditor, where I was involved in the audits of several 6

operating water companies of the American Water Works System and participated in the 7

preparation of annual reports to regulatory agencies and assisted in other general 8

accounting matters. 9

Upon graduation from Drexel University, I was employed by American Water Works 10

Service Company, Inc., in the Eastern Regional Treasury Department where my duties 11

included preparation of rate case exhibits for submission to regulatory agencies, as well as 12

responsibility for various treasury functions of the thirteen New England operating 13

subsidiaries. 14

In 1973, I joined the Municipal Financial Services Department of Betz Environmental 15

Engineers, a consulting engineering firm, where I specialized in financial studies for 16

municipal water and wastewater systems. 17

In 1974, I joined Associated Utility Services, Inc., now known as AUS Consultants. I 18

held various positions with the Utility Services Group of AUS Consultants, concluding my 19

employment there as a Senior Vice President. 20

In 1994, I formed P. Moul & Associates, an independent financial and regulatory 21

consulting firm. In my capacity as Managing Consultant and for the past twenty-nine years, 22

I have continuously studied the rate of return requirements for cost of service-regulated 23

firms. In this regard, I have supervised the preparation of rate of return studies, which were 24

employed, in connection with my testimony and in the past for other individuals. I have 25


A-2

presented direct testimony on the subject of fair rate of return, evaluated rate of return 1

testimony of other witnesses, and presented rebuttal testimony. 2

My studies and prepared direct testimony have been presented before thirty-seven 3

(37) federal, state and municipal regulatory commissions, consisting of: the Federal Energy 4

Regulatory Commission; state public utility commissions in Alabama, Alaska, California, 5

Colorado, Connecticut, Delaware, Florida, Georgia, Hawaii, Illinois, Indiana, Iowa, 6

Kentucky, Louisiana, Maine, Maryland, Massachusetts, Michigan, Minnesota, Missouri, 7

New Hampshire, New Jersey, New York, North Carolina, Ohio, Oklahoma, Pennsylvania, 8

Rhode Island, South Carolina, Tennessee, Texas, Virginia, West Virginia, Wisconsin, and 9

the Philadelphia Gas Commission, and the Texas Commission on Environmental Quality. 10

My testimony has been offered in over 200 rate cases involving electric power, natural gas 11

distribution and transmission, resource recovery, solid waste collection and disposal, 12

telephone, wastewater, and water service utility companies. While my testimony has 13

involved principally fair rate of return and financial matters, I have also testified on capital 14

allocations, capital recovery, cash working capital, income taxes, factoring of accounts 15

receivable, and take-or-pay expense recovery. My testimony has been offered on behalf of 16

municipal and investor-owned public utilities and for the staff of a regulatory commission. I 17

have also testified at an Executive Session of the State of New Jersey Commission of 18

Investigation concerning the BPU regulation of solid waste collection and disposal. 19

I was a co-author of a verified statement submitted to the Interstate Commerce 20

Commission concerning the 1983 Railroad Cost of Capital (Ex Parte No. 452). I was also 21

co-author of comments submitted to the Federal Energy Regulatory Commission regarding 22

the Generic Determination of Rate of Return on Common Equity for Public Utilities in 1985, 23

1986 and 1987 (Docket Nos. RM85-19-000, RM86-12-000, RM87-35-000 and RM88-25-24

000). Further, I have been the consultant to the New York Chapter of the National 25


A-3

Association of Water Companies, which represented the water utility group in the 1

Proceeding on Motion of the Commission to Consider Financial Regulatory Policies for New 2

York Utilities (Case 91-M-0509). I have also submitted comments to the Federal Energy 3

Regulatory Commission in its Notice of Proposed Rulemaking (Docket No. RM99-2-000) 4

concerning Regional Transmission Organizations and on behalf of the Edison Electric 5

Institute in its intervention in the case of Southern California Edison Company (Docket No. 6

ER97-2355-000). Also, I was a member of the panel of participants at the Technical 7

Conference in Docket No. PL07-2 on the Composition of Proxy Groups for Determining Gas 8

and Oil Pipeline Return on Equity. 9

In late 1978, I arranged for the private placement of bonds on behalf of an investor-10

owned public utility. I have assisted in the preparation of a report to the Delaware Public 11

Service Commission relative to the operations of the Lincoln and Ellendale Electric 12

Company. I was also engaged by the Delaware P.S.C. to review and report on the 13

proposed financing and disposition of certain assets of Sussex Shores Water Company 14

(P.S.C. Docket Nos. 24-79 and 47-79). I was a co-author of a Report on Proposed 15

Mandatory Solid Waste Collection Ordinance prepared for the Board of County 16

Commissioners of Collier County, Florida. 17

I have been a consultant to the Bucks County Water and Sewer Authority 18

concerning rates and charges for wholesale contract service with the City of Philadelphia. 19

My municipal consulting experience also included an assignment for Baltimore County, 20

Maryland, regarding the City/County Water Agreement for Metropolitan District customers 21

(Circuit Court for Baltimore County in Case 34/153/87-CSP-2636). 22



* * * * *


EXHIBIT TO ACCOMPANY THE

DIRECT TESTIMONY OF

PAUL R. MOUL

FOR


June 7, 2013

Michigan Gas Utilities Corporation Index of Schedules Schedule Numbers Summary Cost of Equity D6 Michigan Gas Utilities Corporation Historical Capitalization and Financial Statistics D7 Delivery Group Historical Capitalization and Financial Statistics D8 Standard & Poor's Public Utilities Historical Capitalization and Financial Statistics D9 Dividend Yields D10 Historical Growth Rates D11 Projected Growth Rates D12 Financial Risk Adjustment D13 Interest Rates for Investment Grade Public Utility Bonds D14 Common Equity Risk Premiums D15 Component Inputs for the Capital Asset Pricing Model D16 Comparable Earnings Approach D17

Case No.: U-17273Witness: P.R. Moul

Exhibit: A-4 (PRM-1)Schedule: D6

Page 1 of 1

Market Models (DCF, RP & CAPM)

Discounted Cash Flow (DCF) D 1 /P 0 (1) + g (2) + lev. (3) = k

Delivery Group 4.13% + 5.00% + 0.50% = 9.63%

Risk Premium (RP) I (5) + RP (6) = kDelivery Group 5.00% + 7.00% = 12.00%

Capital Asset Pricing Model (CAPM) Rf (7) + ß (8) x ( Rm-Rf (9) ) + size (10) = kDelivery Group 3.50% + 0.73 x ( 8.76% ) + 1.12% = 11.01%

Book Value Method

Comparable Earnings (CE) Historical (11) Forecast (11) AverageComparable Earnings Group 12.4% 13.3% 12.85%

References (1) Attachment PRM-7 page 1(2) Attachment PRM-9 page 1(3) Attachment PRM-10 page 1(4) Attachment PRM-11 page 1(5)

(6) Attachment PRM-13 page 1(7) Attachment PRM-14 pages 1 & 2(8) Attachment PRM-10 page 1(9) Attachment PRM-14 page 2

(10) Attachment PRM-14 page 3(11) Attachment PRM-15 page 2

A-rated public utility bond yield comprised of a 3.50% risk-free rate of return (Attachment PRM-14 page 2) and a yield spread of 1.50% (Attachment PRM-12 page 3)

Michigan Gas Utilities CorporationCost of Equity

as of December 31, 2012



Page 1 of 2

2012 2011 2010 2009 2008

Amount of Capital EmployedPermanent Capital 192.9$ 195.6$ 208.7$ 216.9$ 203.4$ Short-Term Debt -$ -$ 8.8$ 8.8$ 27.1$ Total Capital 192.9$ 195.6$ 217.5$ 225.6$ 230.4$

Capital Structure Ratios AverageBased on Permanent Capital:

Long-Term Debt 43.6% 42.9% 40.2% 38.7% 41.3% 41.3%Common Equity (1) 56.4% 57.1% 59.8% 61.3% 58.7% 58.7%

100.0% 100.0% 100.0% 100.0% 100.0% 100.0%Based on Total Capital:

Total Debt incl. Short Term 43.6% 42.9% 42.7% 41.1% 48.2% 43.7%Common Equity (1) 56.4% 57.1% 57.3% 58.9% 51.8% 56.3%

100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Rate of Return on Book Common Equity (1) 4.7% 6.3% 4.8% 5.7% 5.1% 5.3%

Operating Ratio (2) 89.6% 89.4% 90.9% 90.9% 94.3% 91.0%

Coverage incl. AFUDC (3)

Pre-tax: All Interest Charges 2.59 x 3.06 x 3.17 x 3.34 x 2.75 x 2.98 xPost-tax: All Interest Charges 2.01 x 2.32 x 2.20 x 2.39 x 2.10 x 2.20 x

Coverage excl. AFUDC (3)

Pre-tax: All Interest Charges 2.59 x 3.05 x 3.17 x 3.34 x 2.75 x 2.98 xPost-tax: All Interest Charges 2.01 x 2.32 x 2.20 x 2.39 x 2.10 x 2.20 x

Quality of Earnings & Cash FlowAFC/Income Avail. for Common Equity 0.1% 0.5% 0.0% 0.0% 0.0% 0.1%Effective Income Tax Rate 36.4% 35.7% 44.7% 40.7% 37.4% 39.0%Internal Cash Generation/Construction (4) 51.7% 73.6% 109.0% 67.5% 181.8% 96.7%Gross Cash Flow/ Avg. Total Debt (5) 19.3% 32.1% 24.6% 32.2% 16.0% 24.8%Gross Cash Flow Interest Coverage (6) 3.19 x 5.07 x 4.47 x 6.33 x 3.51 x 4.51 x

See Page 2 for Notes.

(Millions of Dollars)

Michigan Gas Utilities CorporationCapitalization and Financial Statistics

2008-2012, Inclusive

Case No.: U-17273 Witness: P.R. Moul

Exhibit: A-4 (PRM-1) Schedule: D7

Page 2 of 2

Michigan Gas Utilities Corporation Capitalization and Financial Statistics 2005-2009, Inclusive Notes: (1) Excludes Accumulated Other Comprehensive Income (“OCI”). (2) Total operating expenses, maintenance, depreciation and taxes other than income taxes as a

percent of operating revenues. (3) Coverage calculations represent the number of times available earnings, both including

and excluding AFUDC (allowance for funds used during construction) as reported in its entirety, cover fixed charges.

(4) Internal cash generation/gross construction is the percentage of gross construction expenditures provided by internally-generated funds from operations after payment of all cash dividends divided by gross construction expenditures.

(5) Gross Cash Flow (sum of net income, depreciation, amortization, net deferred income taxes and investment tax credits, less total AFUDC) plus interest charges, divided by interest charges.

(6) Gross Cash Flow plus interest charges divided by interest charges.

Source of Information: Company provided data



Page 1 of 2

2012 2011 2010 2009 2008

Amount of Capital EmployedPermanent Capital 5,796.3$ 5,032.1$ 4,676.3$ 4,584.3$ 4,339.5$ Short-Term Debt 478.5$ 296.3$ 214.9$ 182.0$ 338.3$ Total Capital 6,274.8$ 5,328.4$ 4,891.2$ 4,766.3$ 4,677.8$

Market-Based Financial Ratios AveragePrice-Earnings Multiple 17 x 16 x 16 x 17 x 15 x 16 xMarket/Book Ratio 166.7% 168.3% 158.6% 145.8% 160.0% 159.9%Dividend Yield 4.0% 4.1% 4.4% 4.8% 4.2% 4.3%Dividend Payout Ratio 67.8% 67.0% 70.9% 75.0% 61.3% 68.4%

Capital Structure RatiosBased on Permanent Capital:

Long-Term Debt 46.0% 46.0% 46.9% 48.0% 48.6% 47.1%Preferred Stock 0.2% 0.3% 0.4% 0.4% 0.4% 0.3%Common Equity (2) 53.9% 53.7% 52.7% 51.6% 51.0% 52.6%


Total Debt incl. Short Term 51.5% 50.5% 51.4% 52.0% 55.1% 52.1%Preferred Stock 0.2% 0.3% 0.3% 0.4% 0.4% 0.3%Common Equity (2) 48.4% 49.2% 48.3% 47.6% 44.6% 47.6%

100.0% 100.0% 100.0% 100.0% 100.0% 100.0%


Operating Ratio (3) 85.6% 86.7% 87.2% 88.5% 89.6% 87.5%


Pre-tax: All Interest Charges 4.21 x 4.14 x 4.24 x 3.72 x 3.95 x 4.05 xPost-tax: All Interest Charges 3.21 x 3.08 x 3.07 x 2.74 x 2.85 x 2.99 xOverall Coverage: All Int. & Pfd. Div. 3.20 x 3.06 x 3.06 x 2.72 x 2.84 x 2.98 x



Quality of Earnings & Cash FlowAFC/Income Avail. for Common Equity 4.7% 4.5% 4.4% 2.6% 3.5% 3.9%Effective Income Tax Rate 32.6% 35.1% 34.3% 35.0% 37.0% 34.8%Internal Cash Generation/Construction (5) 72.8% 88.1% 108.9% 103.0% 97.9% 94.1%Gross Cash Flow/ Avg. Total Debt (6) 23.9% 24.4% 25.9% 21.4% 20.7% 23.3%Gross Cash Flow Interest Coverage (7) 6.19 x 5.84 x 6.22 x 5.29 x 4.89 x 5.69 xCommon Dividend Coverage (8) 4.01 x 4.05 x 4.57 x 4.11 x 4.18 x 4.18 x



Delivery GroupCapitalization and Financial Statistics (1)




Page 2 of 2

Delivery Group Capitalization and Financial Statistics 2008-2012, Inclusive

Notes: (1) All capitalization and financial statistics for the group are the arithmetic average of the achieved results

for each individual company in the group. (2) Excluding Accumulated Other Comprehensive Income (“OCI”) from the equity account. (3) Total operating expenses, maintenance, depreciation and taxes other than income taxes as a percent

of operating revenues. (4) Coverage calculations represent the number of times available earnings, both including and excluding

AFUDC (allowance for funds used during construction) as reported in its entirety, cover fixed charges. (5) Internal cash generation/gross construction is the percentage of gross construction expenditures

provided by internally-generated funds from operations after payment of all cash dividends divided by gross construction expenditures.


(7) Gross Cash Flow plus interest charges divided by interest charges. (8) Common dividend coverage is the relationship of internally-generated funds from operations after

payment of preferred stock dividends to common dividends paid. Basis of Selection: The Delivery Group includes companies that are contained in The Value Line Investment Survey within the industry group “Natural Gas Utility,” they are not currently the target of a publicly-announced merger or acquisition, and after eliminating NiSource due to its electric and natural gas pipeline/storage operations and UGI Corp. due to its highly diversified businesses. The Delivery Group also includes companies that are listed in the “Electric Utility (East)” section of Value Line, they are not currently the target of a publicly-announced merger or acquisition and they do not have a significant amount of electric generation.

Stock S&P Stock Value LineTicker Company Moody's S&P Traded Ranking Beta

AGL AGL Resources, Inc. A3 BBB+ NYSE A 0.75ATO Atmos Energy Corp. Baa1 BBB+ NYSE A- 0.70ED Consolidated Edison, Inc. A3 A- NYSE B+ 0.60LG Laclede Group Baa1 A NYSE B+ 0.55

NJR New Jersey Resources Corp. Aa3 A NYSE B+ 0.65NU Northeast Utilities Baa1 A- NYSE B+ 0.70

NWN Northwest Natural Gas A3 A+ NYSE A- 0.55POM PEPCO Holdings Baa2 BBB+ NYSE B 0.75PNY Piedmont Natural Gas Co. A3 A NYSE A 0.65SJI South Jersey Industries, Inc. Baa1 BBB+ NYSE A- 0.65

SWX Southwest Gas Corporation Baa2 BBB NYSE B+ 0.75UIL UIL Holdings Baa2 BBB NYSE B 0.70

WGL WGL Holdings, Inc. A2 A+ NYSE B+ 0.65

Average A3 A- B+ 0.67

Corporate Credit Ratings

Source of Information: Utility COMPUSTAT Moody’s Investors Service Standard & Poor’s Corporation



Page 1 of 3

2012 2011 2010 2009 2008

Amount of Capital EmployedPermanent Capital 21,620.0$ 18,840.8$ 17,587.3$ 16,618.6$ 15,620.1$ Short-Term Debt 648.9$ 531.4$ 435.4$ 415.0$ 803.5$ Total Capital 22,268.9$ 19,372.2$ 18,022.7$ 17,033.6$ 16,423.6$

Market-Based Financial Ratios AveragePrice-Earnings Multiple 18 x 15 x 15 x 14 x 14 x 15 xMarket/Book Ratio 164.0% 155.2% 142.8% 137.1% 174.9% 154.8%Dividend Yield 4.1% 4.4% 4.8% 5.2% 4.3% 4.6%Dividend Payout Ratio 70.3% 64.7% 72.0% 72.2% 61.9% 68.2%

Capital Structure RatiosBased on Permanent Captial:

Long-Term Debt 52.9% 52.9% 53.4% 54.2% 54.3% 53.5%Preferred Stock 1.6% 1.3% 1.3% 1.5% 1.7% 1.5%Common Equity (2) 45.5% 45.8% 45.3% 44.3% 44.0% 45.0%


Total Debt incl. Short Term 54.5% 54.5% 54.7% 55.6% 57.1% 55.3%Preferred Stock 1.6% 1.3% 1.3% 1.4% 1.6% 1.4%Common Equity (2) 44.0% 44.3% 44.0% 43.0% 41.3% 43.3%

100.0% 100.0% 100.0% 100.0% 100.0% 100.0%


Operating Ratio (3) 81.3% 81.4% 81.6% 83.0% 84.1% 82.3%





Quality of Earnings & Cash FlowAFC/Income Avail. for Common Equity 7.1% 5.7% 6.6% 7.8% 7.7% 7.0%Effective Income Tax Rate 26.2% 36.8% 34.3% 31.8% 33.8% 32.6%Internal Cash Generation/Construction (5) 75.0% 89.4% 108.0% 100.0% 83.1% 91.1%Gross Cash Flow/ Avg. Total Debt (6) 21.9% 23.2% 23.9% 22.5% 22.6% 22.8%Gross Cash Flow Interest Coverage (7) 5.37 x 5.12 x 5.09 x 4.85 x 4.75 x 5.04 xCommon Dividend Coverage (8) 4.31 x 4.58 x 4.88 x 4.73 x 4.95 x 4.69 x



Standard & Poor's Public UtilitiesCapitalization and Financial Statistics (1)




Page 2 of 3

Standard & Poor's Public Utilities Capitalization and Financial Statistics

2008-2012, Inclusive Notes:

(1) All capitalization and financial statistics for the group are the arithmetic average of the

achieved results for each individual company in the group. (2) Excluding Accumulated Other Comprehensive Income (“OCI”) from the equity account (3) Total operating expenses, maintenance, depreciation and taxes other than income taxes as

a percent of operating revenues. (4) Coverage calculations represent the number of times available earnings, both including and

excluding AFUDC (allowance for funds used during construction) as reported in its entirety, cover fixed charges.

(5) Internal cash generation/gross construction is the percentage of gross construction expenditures provided by internally-generated funds from operations after payment of all cash dividends divided by gross construction expenditures.

(6) Gross Cash Flow (sum of net income, depreciation, amortization, net deferred income taxes and investment tax credits, less total AFUDC) as a percentage of average total debt.


(8) Common dividend coverage is the relationship of internally-generated funds from operations after payment of preferred stock dividends to common dividends paid.

Source of Information: Annual Reports to Shareholders Utility COMPUSTAT



Page 3 of 3

Common S&P ValueStock Stock Line

Ticker Moody's S&P Traded Ranking Beta

AGL Resources Inc. GAS A3 BBB+ NYSE A 0.75Ameren Corporation AEE Baa2 BBB NYSE B 0.80American Electric Power AEP Baa2 BBB NYSE B 0.70CMS Energy CMS Baa1 BBB NYSE B 0.75CenterPoint Energy CNP Baa2 BBB+ NYSE B 0.80Consolidated Edison ED A3 A- NYSE B+ 0.60DTE Energy Co. DTE A3 BBB+ NYSE B+ 0.75Dominion Resources D A3 A- NYSE B+ 0.65Duke Energy DUK A3 BBB+ NYSE B 0.60Edison Int'l EIX A3 BBB+ NYSE B 0.75Entergy Corp. ETR Baa2 BBB NYSE A+ 0.70EQT Corp. EQT Baa3 BBB NYSE B+ 1.15Exelon Corp. EXC A3 BBB NYSE B+ 0.80FirstEnergy Corp. FE Baa2 BBB- NYSE A- 0.80Integrys Energy Group TEG A2 A- NYSE B 0.90NextEra Energy Inc. NEE A2 A- NYSE A 0.75NiSource Inc. NI Baa2 BBB- NYSE B 0.85Northeast Utilities NU Baa2 A- NYSE B 0.70NRG Energy Inc. NRG Ba3 BB- NYSE NR 1.10ONEOK, Inc. OKE Baa2 BBB NYSE NR 0.95PEPCO Holdings, Inc. POM Baa2 BBB+ NYSE B 0.75PG&E Corp. PCG A3 BBB NYSE B 0.55PPL Corp. PPL Baa2 BBB NYSE B+ 0.65Pinnacle West Capital PNW Baa1 BBB+ NYSE B 0.70Public Serv. Enterprise Inc. PEG A3 BBB NYSE B+ 0.75SCANA Corp. SCG Baa2 BBB+ NYSE A- 0.65Sempra Energy SRE A2 A NYSE A- 0.80Southern Co. SO A3 A NYSE A- 0.55TECO Energy TE A3 BBB+ NYSE B 0.85Wisconsin Energy Corp. WEC A2 A- NYSE A 0.65Xcel Energy Inc XEL A3 A- NYSE B+ 0.65

Average for S&P Utilities Baa1 BBB+ A 0.75

Note: (1) Ratings are those of utility subsidiaries

Source of Information: Moody's Investors ServiceStandard & Poor's Corporation

Standard & Poor's Stock GuideValue Line Investment Survey for Windows

Company IdentitiesStandard & Poor's Public Utilities

Credit Rating (1)



Page 1 of 1

Delivery Group

12-Month 6-Month 3-MonthCompany Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Average Average Average

AGL RES INC (NYSE:GAS) 4.47% 4.62% 4.72% 4.71% 4.92% 4.78% 4.59% 4.65% 4.52% 4.55% 4.73% 4.63%ATMOS ENERGY CORP (NYSE:ATO) 4.29% 4.49% 4.41% 4.27% 4.17% 3.95% 3.88% 3.95% 3.87% 3.92% 4.00% 4.00%Consolidated Edison, Inc. (NYSE:ED) 4.14% 4.17% 4.16% 4.11% 4.02% 3.91% 3.78% 4.00% 4.06% 4.04% 4.35% 4.38%LACLEDE GROUP INC (NYSE:LG) 4.01% 4.08% 4.27% 4.24% 4.40% 4.18% 4.00% 3.97% 3.87% 4.11% 4.22% 4.42%NEW JERSEY RES (NYSE:NJR) 3.20% 3.28% 3.42% 3.53% 3.65% 3.49% 3.50% 3.60% 3.50% 3.61% 3.97% 4.05%Northeast Utilities (NYSE:NU) 3.39% 3.27% 3.17% 3.76% 3.81% 3.55% 3.46% 3.64% 3.60% 3.51% 3.54% 3.52%NORTHWEST NAT GAS CO (NYSE:NWN) 3.75% 3.90% 3.95% 3.90% 3.85% 3.76% 3.66% 3.63% 3.64% 3.91% 4.16% 4.15%PEPCO Holdings Inc. (NYSE:POM) 5.54% 5.63% 5.74% 5.76% 5.74% 5.54% 5.45% 5.67% 5.74% 5.48% 5.54% 5.53%PIEDMONT NAT GAS INC (NYSE:PNY) 3.66% 3.73% 3.87% 3.95% 3.99% 3.73% 3.79% 3.87% 3.70% 3.78% 3.92% 3.84%SOUTH JERSEY INDS INC (NYSE:SJI) 2.95% 3.12% 3.22% 3.28% 3.35% 3.17% 3.06% 3.20% 3.05% 3.52% 3.57% 3.53%SOUTHWEST GAS CORPORATION (SWX) 2.55% 2.49% 2.49% 2.82% 2.82% 2.71% 2.66% 2.76% 2.68% 2.73% 2.82% 2.79%UIL Holdings Corporation (NYSE:UIL) 5.03% 4.95% 4.99% 5.06% 5.17% 4.83% 4.69% 4.96% 4.83% 4.81% 4.87% 4.83%WGL HLDGS INC (NYSE:WGL) 3.64% 3.82% 3.84% 4.00% 4.13% 4.06% 3.97% 4.12% 4.01% 4.03% 4.12% 4.12%

Average 3.89% 3.97% 4.02% 4.11% 4.16% 3.97% 3.88% 4.00% 3.93% 4.00% 4.14% 4.14% 4.02% 4.02% 4.09%

Note:

Source of Information: http://finance.yahoo.com/http://www.nasdaq.com/symbol/gas/dividend-history

Forward-looking Dividend Yield 1/2 Growth D0/P0 (.5g) D1/P0

4.02% 1.025000 4.12%

Discrete D0/P0 Adj. D1/P0

4.02% 1.031059 4.14%

Quarterly D0/P0 Adj. D1/P0

1.0038% 1.012272 4.13%

Average 4.13%

Growth rate 5.00%

K 9.13%

Monthly Dividend Yields for

for the Twelve Months Ending December 2012

Monthly dividend yields are calculated by dividing the annualized quarterly dividend by the month-end closing stock price adjusted by the fraction of the ex-dividend.

P)g + (1 D + )g + (1 D + )g + (1 D + )g + (1 D

0

10

10

00

00

P)g + (1 D + )g + (1 D + )g + (1 D + )g + (1 D

0

1.000

.750

.500

.250

1- P

)g + (1 D + 10

.250

4



Page 1 of 1

Dividends per Share Book Value per Share Cash Flow per ShareValue Line Value Line Value Line Value Line

Delivery Group 5 Year 10 Year 5 Year 10 Year 5 Year 10 Year 5 Year 10 Year

AGL Resources, Inc. 4.50% 9.00% 7.50% 5.00% 5.50% 7.00% 6.00% 6.50%Atmos Energy Corp. 4.00% 7.00% 1.50% 1.50% 4.50% 6.50% 4.50% 4.50%Consolidated Edison 4.50% 1.00% 1.00% 1.00% 4.50% 4.00% 4.50% 1.00%Laclede Group, Inc. 6.00% 6.50% 2.50% 1.50% 6.50% 5.00% 7.00% 5.00%New Jersey Resources Corp. 7.00% 7.50% 8.00% 6.00% 7.50% 8.00% 4.50% 5.00%Northeast Utilities 18.00% - 8.50% 12.50% 3.50% 3.00% 2.00% -2.50%Northwest Natural Gas 4.50% 4.00% 4.50% 3.00% 4.00% 4.00% 3.50% 3.00%PEPCO Holdings -4.50% -4.50% 1.50% - 0.50% 0.50% -4.00% -4.50%Piedmont Natural Gas Co. 4.50% 5.00% 4.00% 4.50% 3.00% 5.00% 4.00% 5.50%South Jersey Industries, Inc. 7.00% 9.50% 9.50% 6.50% 7.00% 10.50% 8.00% 8.00%Southwest Gas Corporation 6.50% 6.00% 4.00% 2.00% 5.00% 4.50% 3.00% 3.50%UIL Holdings 4.50% -2.00% - - -0.50% - 1.50% -2.00%WGL Holdings, Inc. 3.00% 3.00% 2.50% 2.00% 5.00% 4.00% 1.50% 3.00%

Average 5.35% 4.33% 4.58% 4.14% 4.31% 5.17% 3.54% 2.77%

Source of Information: Value Line Investment Survey, December 7, 2012

Historical Growth RatesEarnings Per Share, Dividends Per Share,

Book Value Per Share, and Cash Flow Per Share

Earnings per Share



Page 1 of 1

Analysts' Five-Year Projected Growth RatesEarnings Per Share, Dividends Per Share,

Book Value Per Share, and Cash Flow Per Share

Value LineI/B/E/S Book Cash PercentFirst Earnings Dividends Value Flow Retained to

Delivery Group Call Zacks Morningstar Per Share Per Share Per Share Per Share Common Equity

AGL Resources, Inc. NMF 4.40% 4.60% 6.00% 1.50% 5.00% 9.00% 6.50%Atmos Energy Corp. 6.00% 6.00% 8.50% 4.00% 1.50% 6.00% 3.50% 3.50%Consolidated Edison 2.41% 3.00% 2.80% 4.00% 1.00% 4.00% 5.50% 4.00%Laclede Group, Inc. 5.30% 3.00% - 3.00% 2.50% 4.50% 2.50% 4.50%New Jersey Resources Corp. 2.70% 4.00% 4.30% 5.50% 4.00% 5.50% 5.00% 7.50%Northeast Utilities 5.90% 7.10% 8.10% 8.00% 8.50% 8.00% 4.00% 4.50%Northwest Natural Gas 4.50% 4.20% 3.00% 3.00% 2.50% 1.00% -0.50% 4.00%PEPCO Holdings 4.33% 4.80% 4.10% 7.00% 1.00% 2.00% 4.00% 2.50%Piedmont Natural Gas Co. 5.35% 3.70% 5.30% 2.50% 3.50% 1.50% 2.50% 3.50%South Jersey Industries, Inc. 6.00% 6.00% - 9.00% 9.00% 6.00% 7.00% 7.50%Southwest Gas Corporation 4.05% 5.00% - 9.00% 8.00% 6.00% 6.50% 6.00%UIL Holdings 4.10% 4.00% 4.00% 4.00% Nil 3.50% 3.50% 3.00%WGL Holdings, Inc. 5.60% 5.30% 5.00% 2.50% 2.50% 4.00% 1.50% 3.50%

Average 4.69% 4.65% 4.97% 5.19% 3.79% 4.38% 4.15% 4.65%

Source of Information : IBES/First Call, January 18, 2013Zacks, January 18, 2013Morningstar, January 18, 2013Value Line Investment Survey, December 7, 2012



Page 1 of 1AGL Resources

(NYSE:GAS) ATMOS Energy

(NYSE:ATO)

Consolidated Edison

(NYSE:ED)Laclede Group

(NYSE:LG)

New Jersey Resources

(NYSE:NJR)

Northeast Utilities

(NYSE:NU)

Northwest Natural Gas

(NYSE:NWN)

PEPCO Holdings

(NYSE:POM)

Piedmont Natural Gas (NYSE:PNY)

South Jersey Industries

(NYSE:SJI) Southwest Gas

(SWX)UIL Holdings (NYSE:UIL)

WGL Holdings (NYSE:WGL) Average

Fiscal Year 12/31/12 09/30/12 12/31/12 09/30/12 09/30/12 12/31/12 12/31/12 12/31/12 10/31/12 12/31/12 12/31/12 12/31/2011 09/30/12

Capitalization at Fair ValuesDebt(D) 4,057,000 2,426,434 12,935,000 452,768 583,140 8,640,700 834,664 5,004,000 1,163,227 682,300 1,482,095 1,900,000 758,900 3,147,710Preferred(P) 0 0 0 0 0 152,200 0 0 0 0 0 340 28,173 13,901Equity(E) 4,710,667 3,229,686 14,976,983 969,196 1,776,495 12,273,216 1,189,731 4,510,603 2,302,608 1,593,109 1,957,128 1,813,615 2,077,369 4,106,185Total 8,767,667 5,656,120 27,911,983 1,421,964 2,359,635 21,066,116 2,024,395 9,514,603 3,465,835 2,275,409 3,439,223 3,713,955 2,864,442 7,267,796

Capital Structure RatiosDebt(D) 46.27% 42.90% 46.34% 31.84% 24.71% 41.02% 41.23% 52.59% 33.56% 29.99% 43.09% 51.16% 26.49% 39.32%Preferred(P) 0.00% 0.00% 0.00% 0.00% 0.00% 0.72% 0.00% 0.00% 0.00% 0.00% 0.00% 0.01% 0.98% 0.13%Equity(E) 53.73% 57.10% 53.66% 68.16% 75.29% 58.26% 58.77% 47.41% 66.44% 70.01% 56.91% 48.83% 72.52% 60.55%Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 99.99% 100.00%

Common StockIssued 117,855.075 90,239.900 292,871.896 22,539.431 41,619.633 26,917.000 230,015.427 72,250.000 46,147.788 50,645.490 51,611.647Treasury 0.000 0.000 23,210.700 0.000 2,763.659 0.000 0.000 0.000 0.000 0.000 0.000Outstanding 117,855.075 90,239.900 269,661.196 22,539.431 38,855.974 314,053.634 26,917.000 230,015.427 72,250.000 31,653.262 46,147.788 50,645.490 51,611.647Market Price 39.97$ 35.79$ $55.54 43.00$ 45.72$ $39.08 44.20$ 19.61$ 31.87$ 50.33$ 42.41$ 35.81$ 40.25$

Capitalization at Carrying AmountsDebt(D) 3,553,000 1,960,131 10,768,000 364,416 532,929 7,963,500 691,700 4,177,000 975,000 626,400 1,318,510 1,610,550 589,200 2,702,334Preferred(P) 0 0 0 0 0 155,600 0 0 0 0 0 340 28,173 14,163Equity(E) 3,413,000 2,359,243 11,869,000 601,611 813,865 9,237,050 733,033 4,446,000 1,027,004 736,214 1,310,179 1,116,553 1,269,556 2,994,793Total 6,966,000 4,319,374 22,637,000 966,027 1,346,794 17,356,150 1,424,733 8,623,000 2,002,004 1,362,614 2,628,689 2,727,443 1,886,929 5,711,289

Capital Structure RatiosDebt(D) 51.00% 45.38% 47.57% 37.72% 39.57% 45.88% 48.55% 48.44% 48.70% 45.97% 50.16% 59.05% 31.23% 46.09%Preferred(P) 0.00% 0.00% 0.00% 0.00% 0.00% 0.90% 0.00% 0.00% 0.00% 0.00% 0.00% 0.01% 1.49% 0.18%Equity(E) 49.00% 54.62% 52.43% 62.28% 60.43% 53.22% 51.45% 51.56% 51.30% 54.03% 49.84% 40.94% 67.28% 53.72%Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%

Betas Value Line 0.75 0.70 0.60 0.55 0.65 0.70 0.55 0.75 0.65 0.65 0.75 0.70 0.65 0.67

Hamada Bl = Bu [1+ (1 - t ) D/E + P/E ]0.67 = Bu [1+ (1-0.35) 0.6494 + 0.0021 ]0.67 = Bu [1+ 0.65 0.6494 + 0.0021 ]0.67 = Bu 1.42420.47 = Bu

Hamada Bl = 0.47 [1+ (1 - t) D/E + P/E ]Bl = 0.47 [1+ 0.65 0.8580 + 0.0034 ]Bl = 0.47 1.5611Bl = 0.73

M&M ku = ke - ((( ku - i ) 1-t ) D / E - (ku - d ) P / E7.59% = 9.13% - ((( 7.59% - 3.95% ) 0.65 ) 39.32% / 60.55% - 7.59% - 5.68% ) 0.13% / 60.55%7.59% = 9.13% - ((( 3.64% ) 0.65 ) 0.6494 - 1.91% ) 0.00217.59% = 9.13% - (( 2.37% ) 0.6494 - 1.91% ) 0.00217.59% = 9.13% - 1.54% - 0.00%

M&M ke = ku + ((( ku - i ) 1-t ) D / E + (ku - d ) P / E9.63% = 7.59% + ((( 7.59% - 3.95% ) 0.65 ) 46.09% / 53.72% + 7.59% - 5.68% ) 0.18% / 53.72%9.63% = 7.59% + ((( 3.64% ) 0.65 ) 0.8580 + 1.91% ) 0.00349.63% = 7.59% + (( 2.37% ) 0.858 + 1.91% ) 0.00349.63% = 7.59% + 2.03% + 0.01%

Delivery GroupFinancial Risk Adjustment



Page 1 of 3

Aa A BaaYears Rated Rated Rated Average

2008 6.18% 6.53% 7.24% 6.65%2009 5.75% 6.04% 7.06% 6.28%2010 5.24% 5.46% 5.96% 5.55%2011 4.78% 5.04% 5.57% 5.13%2012 3.83% 4.13% 4.86% 4.27%

Five-YearAverage 5.16% 5.44% 6.14% 5.58%

Months

Jan-12 4.03% 4.34% 5.06% 4.48%Feb-12 4.02% 4.36% 5.02% 4.47%Mar-12 4.16% 4.48% 5.13% 4.59%Apr-12 4.10% 4.40% 5.11% 4.53%

May-12 3.92% 4.20% 4.97% 4.36%Jun-12 3.79% 4.08% 4.91% 4.26%Jul-12 3.58% 3.93% 4.85% 4.12%

Aug-12 3.65% 4.00% 4.88% 4.18%Sep-12 3.69% 4.02% 4.81% 4.17%Oct-12 3.68% 3.91% 4.54% 4.04%Nov-12 3.60% 3.84% 4.42% 3.95%Dec-12 3.75% 4.00% 4.56% 4.10%

Twelve-MonthAverage 3.83% 4.13% 4.86% 4.27%

Six-MonthAverage 3.66% 3.95% 4.68% 4.09%

Three-MonthAverage 3.68% 3.92% 4.51% 4.03%

Interest Rates for Investment Grade Public Utility BondsYearly for 2008-2012

and the Twelve Months Ended December 2012

Source: Mergent Bond Record

Yields onA-rated Public Utility Bonds and Spreads over 20-Year Treasuries

0.00%

1.00%

2.00%

3.00%

4.00%

5.00%

6.00%

7.00%

8.00%

9.00%

A-rated Public Utility 8.31% 7.89% 7.75% 7.60% 7.04% 7.62% 8.24% 7.76% 7.37% 6.58% 6.16% 5.65% 6.07% 6.07% 6.53% 6.04% 5.46% 5.04% 4.13%

Spread vs. 20-year 0.82% 0.94% 0.92% 0.91% 1.32% 1.42% 2.01% 2.13% 1.94% 1.62% 1.12% 1.01% 1.08% 1.16% 2.17% 1.93% 1.43% 1.42% 1.59%

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Case N

o.: U-17273

Witness: P.R

. Moul

Exhibit: A-4 (PRM

-1) Schedule: D

14 Page 2 of 3



Page 3 of 3

A-rated A-rated A-ratedYear Public Utility Yield Spread Year Public Utility Yield Spread Year Public Utility Yield Spread

Dec-98 6.91% 5.36% 1.55%

Jan-99 6.97% 5.45% 1.52% Jan-04 6.15% 5.01% 1.14% Jan-09 6.39% 3.46% 2.93%Feb-99 7.09% 5.66% 1.43% Feb-04 6.15% 4.94% 1.21% Feb-09 6.30% 3.83% 2.47%Mar-99 7.26% 5.87% 1.39% Mar-04 5.97% 4.72% 1.25% Mar-09 6.42% 3.78% 2.64%Apr-99 7.22% 5.82% 1.40% Apr-04 6.35% 5.16% 1.19% Apr-09 6.48% 3.84% 2.64%May-99 7.47% 6.08% 1.39% May-04 6.62% 5.46% 1.16% May-09 6.49% 4.22% 2.27%Jun-99 7.74% 6.36% 1.38% Jun-04 6.46% 5.45% 1.01% Jun-09 6.20% 4.51% 1.69%Jul-99 7.71% 6.28% 1.43% Jul-04 6.27% 5.24% 1.03% Jul-09 5.97% 4.38% 1.59%Aug-99 7.91% 6.43% 1.48% Aug-04 6.14% 5.07% 1.07% Aug-09 5.71% 4.33% 1.38%Sep-99 7.93% 6.50% 1.43% Sep-04 5.98% 4.89% 1.09% Sep-09 5.53% 4.14% 1.39%Oct-99 8.06% 6.66% 1.40% Oct-04 5.94% 4.85% 1.09% Oct-09 5.55% 4.16% 1.39%Nov-99 7.94% 6.48% 1.46% Nov-04 5.97% 4.89% 1.08% Nov-09 5.64% 4.24% 1.40%Dec-99 8.14% 6.69% 1.45% Dec-04 5.92% 4.88% 1.04% Dec-09 5.79% 4.40% 1.39%




Jan-03 7.07% 5.02% 2.05% Jan-08 6.02% 4.35% 1.67%Feb-03 6.93% 4.87% 2.06% Feb-08 6.21% 4.49% 1.72% Average:Mar-03 6.79% 4.82% 1.97% Mar-08 6.21% 4.36% 1.85% 12-months 1.59%Apr-03 6.64% 4.91% 1.73% Apr-08 6.29% 4.44% 1.85% 6-months 1.54%May-03 6.36% 4.52% 1.84% May-08 6.28% 4.60% 1.68% 3-months 1.46%Jun-03 6.21% 4.34% 1.87% Jun-08 6.38% 4.74% 1.64%Jul-03 6.57% 4.92% 1.65% Jul-08 6.40% 4.62% 1.78%Aug-03 6.78% 5.39% 1.39% Aug-08 6.37% 4.53% 1.84%Sep-03 6.56% 5.21% 1.35% Sep-08 6.49% 4.32% 2.17%Oct-03 6.43% 5.21% 1.22% Oct-08 7.56% 4.45% 3.11%Nov-03 6.37% 5.17% 1.20% Nov-08 7.60% 4.27% 3.33%Dec-03 6.27% 5.11% 1.16% Dec-08 6.52% 3.18% 3.34%

20-Year Treasuries 20-Year Treasuries

A rated Public Utility Bonds over 20-Year Treasuries

20-Year Treasuries



Page 1 of 2

Common Equity Risk PremiumsYears 1926-2012

Large Common Stocks

Long-Term Corp. Bonds

Equity Risk

PremiumLong-Term Govt.

Bonds Yields

Low Interest Rates 11.72% 4.72% 7.00% 3.03%

Average Across All Interest Rates 11.82% 6.41% 5.41% 5.16%

High Interest Rates 11.92% 8.15% 3.77% 7.35%

Source of Information: 2013 Stocks, Bonds, Bills, and Inflation (SBBI) Classis Yearbook



Page 2 of 2Basic Series

Annual Total Returns (except yields)

Year

Large Common Stocks

Long-Term Corp. Bonds

Stocks vs.

Corp. Bonds

Long-Term Govt.

Bonds Yields

1940 -9.78% 3.39% -13.17% 1.94%1945 36.44% 4.08% 32.36% 1.99%1941 -11.59% 2.73% -14.32% 2.04%1949 18.79% 3.31% 15.48% 2.09%1946 -8.07% 1.72% -9.79% 2.12%1950 31.71% 2.12% 29.59% 2.24%1939 -0.41% 3.97% -4.38% 2.26%1948 5.50% 4.14% 1.36% 2.37%2012 16.00% 10.68% 5.32% 2.41%1947 5.71% -2.34% 8.05% 2.43%1942 20.34% 2.60% 17.74% 2.46%1944 19.75% 4.73% 15.02% 2.46%1943 25.90% 2.83% 23.07% 2.48%2011 2.11% 17.95% -15.84% 2.48%1938 31.12% 6.13% 24.99% 2.52%1936 33.92% 6.74% 27.18% 2.55%1951 24.02% -2.69% 26.71% 2.69%1954 52.62% 5.39% 47.23% 2.72%1937 -35.03% 2.75% -37.78% 2.73%1953 -0.99% 3.41% -4.40% 2.74%1935 47.67% 9.61% 38.06% 2.76%1952 18.37% 3.52% 14.85% 2.79%1934 -1.44% 13.84% -15.28% 2.93%1955 31.56% 0.48% 31.08% 2.95%2008 -37.00% 8.78% -45.78% 3.03%1932 -8.19% 10.82% -19.01% 3.15%1927 37.49% 7.44% 30.05% 3.16%1957 -10.78% 8.71% -19.49% 3.23%1930 -24.90% 7.98% -32.88% 3.30%1933 53.99% 10.38% 43.61% 3.36%1928 43.61% 2.84% 40.77% 3.40%1929 -8.42% 3.27% -11.69% 3.40%1956 6.56% -6.81% 13.37% 3.45%1926 11.62% 7.37% 4.25% 3.54%1960 0.47% 9.07% -8.60% 3.80%1958 43.36% -2.22% 45.58% 3.82%1962 -8.73% 7.95% -16.68% 3.95%1931 -43.34% -1.85% -41.49% 4.07%2010 15.06% 12.44% 2.62% 4.14%1961 26.89% 4.82% 22.07% 4.15%1963 22.80% 2.19% 20.61% 4.17%1964 16.48% 4.77% 11.71% 4.23%1959 11.96% -0.97% 12.93% 4.47%1965 12.45% -0.46% 12.91% 4.50%

2007 5.49% 2.60% 2.89% 4.50%1966 -10.06% 0.20% -10.26% 4.55%2009 26.46% 3.02% 23.44% 4.58%2005 4.91% 5.87% -0.96% 4.61%2002 -22.10% 16.33% -38.43% 4.84%2004 10.88% 8.72% 2.16% 4.84%2006 15.79% 3.24% 12.55% 4.91%2003 28.68% 5.27% 23.41% 5.11%1998 28.58% 10.76% 17.82% 5.42%1967 23.98% -4.95% 28.93% 5.56%2000 -9.10% 12.87% -21.97% 5.58%2001 -11.89% 10.65% -22.54% 5.75%1971 14.30% 11.01% 3.29% 5.97%1968 11.06% 2.57% 8.49% 5.98%1972 18.99% 7.26% 11.73% 5.99%1997 33.36% 12.95% 20.41% 6.02%1995 37.58% 27.20% 10.38% 6.03%1970 3.86% 18.37% -14.51% 6.48%1993 10.08% 13.19% -3.11% 6.54%1996 22.96% 1.40% 21.56% 6.73%1999 21.04% -7.45% 28.49% 6.82%1969 -8.50% -8.09% -0.41% 6.87%1976 23.93% 18.65% 5.28% 7.21%1973 -14.69% 1.14% -15.83% 7.26%1992 7.62% 9.39% -1.77% 7.26%1991 30.47% 19.89% 10.58% 7.30%1974 -26.47% -3.06% -23.41% 7.60%1986 18.67% 19.85% -1.18% 7.89%1994 1.32% -5.76% 7.08% 7.99%1977 -7.16% 1.71% -8.87% 8.03%1975 37.23% 14.64% 22.59% 8.05%1989 31.69% 16.23% 15.46% 8.16%1990 -3.10% 6.78% -9.88% 8.44%1978 6.57% -0.07% 6.64% 8.98%1988 16.61% 10.70% 5.91% 9.18%1987 5.25% -0.27% 5.52% 9.20%1985 31.73% 30.09% 1.64% 9.56%1979 18.61% -4.18% 22.79% 10.12%1982 21.55% 42.56% -21.01% 10.95%1984 6.27% 16.86% -10.59% 11.70%1983 22.56% 6.26% 16.30% 11.97%1980 32.50% -2.76% 35.26% 11.99%1981 -4.92% -1.24% -3.68% 13.34%



Page 1 of 3

Years 1-Year 2-Year 3-Year 5-Year 7-Year 10-Year 20-Year 30-Year

2008 1.82% 2.00% 2.24% 2.80% 3.17% 3.67% 4.36% 4.28%2009 0.47% 0.96% 1.43% 2.19% 2.81% 3.26% 4.11% 4.08%2010 0.32% 0.70% 1.11% 1.93% 2.62% 3.21% 4.03% 4.25%2011 0.18% 0.45% 0.75% 1.52% 2.16% 2.79% 3.62% 3.91%2012 0.18% 0.28% 0.38% 0.76% 1.22% 1.80% 2.54% 2.92%

Five-YearAverage 0.59% 0.88% 1.18% 1.84% 2.40% 2.95% 3.73% 3.89%

Months

Jan-12 0.12% 0.24% 0.36% 0.84% 1.38% 1.97% 2.70% 3.03%Feb-12 0.16% 0.28% 0.38% 0.83% 1.37% 1.97% 2.75% 3.11%Mar-12 0.19% 0.34% 0.51% 1.02% 1.56% 2.17% 2.94% 3.28%Apr-12 0.18% 0.29% 0.43% 0.89% 1.43% 2.05% 2.82% 3.18%

May-12 0.19% 0.29% 0.39% 0.76% 1.21% 1.80% 2.53% 2.93%Jun-12 0.19% 0.29% 0.39% 0.71% 1.08% 1.62% 2.31% 2.70%Jul-12 0.19% 0.25% 0.33% 0.62% 0.98% 1.53% 2.22% 2.59%

Aug-12 0.18% 0.27% 0.37% 0.71% 1.14% 1.68% 2.40% 2.77%Sep-12 0.18% 0.26% 0.34% 0.67% 1.12% 1.72% 2.49% 2.88%Oct-12 0.18% 0.28% 0.37% 0.71% 1.15% 1.75% 2.51% 2.90%Nov-12 0.18% 0.27% 0.36% 0.67% 1.08% 1.65% 2.39% 2.80%Dec-12 0.16% 0.26% 0.35% 0.70% 1.13% 1.72% 2.47% 2.88%

Twelve-Month Average 0.18% 0.28% 0.38% 0.76% 1.22% 1.80% 2.54% 2.92%

Six-MonthAverage 0.18% 0.27% 0.35% 0.68% 1.10% 1.68% 2.41% 2.80%

Three-MonthAverage 0.17% 0.27% 0.36% 0.69% 1.12% 1.71% 2.46% 2.86%

Source: Federal Reserve statistical release H.15

Yields for Treasury Constant MaturitiesYearly for 2008-2012

and the Twelve Months Ended December 2012



Page 2 of 3

1-Year 2-Year 5-Year 10-Year 30-Year Aaa BaaYear Quarter Bill Note Note Note Bond Bond Bond

2013 First 0.2% 0.3% 0.8% 1.8% 2.9% 3.7% 4.8%2013 Second 0.2% 0.3% 0.9% 1.9% 3.0% 3.8% 4.9%2013 Third 0.2% 0.4% 0.9% 2.0% 3.1% 3.9% 4.9%2013 Fourth 0.3% 0.4% 1.1% 2.1% 3.2% 3.9% 5.0%2014 First 0.3% 0.5% 1.2% 2.2% 3.3% 4.0% 5.1%2014 Second 0.4% 0.6% 1.3% 2.3% 3.4% 4.1% 5.2%

Median Median Dividend Appreciation Total

As of: Yield Potential Return2.2% + 10.67% = 12.87%

D/P ( 1+.5g ) + g = k2.51% ( 1.0457 ) + 9.14% = 11.76%

where: Price (P) at = 1426.19Dividend (D) for = 8.94Dividend (D) = 35.76Growth (g) = 9.14%

Value Line 12.87%S&P 500 11.76%

Average 12.32%Risk-free Rate of Return 3.50%

Forecast Market Premium 8.82%

Historical Market Premium (Rm) (Rf)1926-2012 Arith. mean 11.72% 3.03% 8.69%

Average - Forecast/Historical 8.76%

Measures of the Risk-Free Rate & Corporate Bond YieldsThe forecast of Treasury and Corporate yields

per the consensus of nearly 50 economists reported in the Blue Chip Financial Forecasts dated January 1, 2013

CorporateTreasury

annualizedFirst Call EpS

Summary

Measures of the Market Premium

Value Line Return

DCF Result for the S&P 500 Composite

31-Dec-124th Qtr. '12

January 18, 2013

Case No.: U-17273 Witness: P.R. Moul Exhibit: A-4 (PRM-1) Schedule: D16 Page 3 of 3



Page 1 of 2

Timeliness Safety Financial Price TechnicalCompany Industry Rank Rank Strength Stability Beta Rank

Altria Group TOBACCO 2 2 B+ 100 0.55 3AmerisourceBergen MEDICNON 3 2 B++ 100 0.70 2Berkley (W.R.) INSPRPTY 2 2 B++ 95 0.70 2Campbell Soup FOODPROC 2 2 B++ 100 0.55 2Capitol Fed. Fin'l THRIFT 3 3 B+ 95 0.65 3Church & Dwight HOUSEPRD 2 1 A 100 0.60 3Clorox Co. HOUSEPRD 2 2 B++ 100 0.60 3DaVita Inc. MEDSERV 2 3 B+ 95 0.70 3Dollar General RETAIL 2 3 B++ 95 0.60 3Erie Indemnity Co. INSPRPTY 3 2 B++ 100 0.75 2Haemonetics Corp. MEDICNON 3 2 B++ 95 0.65 3Hershey Co. FOODPROC 2 2 B++ 100 0.65 2Hormel Foods FOODPROC 3 1 A 100 0.65 3Kellogg FOODPROC 3 1 A 100 0.55 3Kroger Co. GROCERY 3 2 B++ 95 0.60 3Laboratory Corp. MEDSERV 3 1 A 100 0.65 3Marsh & McLennan FINSERV 3 3 B 95 0.75 3People's United Fin'l THRIFT 3 3 B+ 95 0.70 3Philip Morris Int'l TOBACCO 3 2 B++ 95 0.75 3Quest Diagnostics MEDSERV 3 2 B++ 95 0.75 3Silgan Holdings PACKAGE 3 3 B+ 95 0.75 3Stericycle Inc. ENVIRONM 2 2 B++ 95 0.70 3Verisk Analytics INFOSER 2 2 B+ 100 0.60 3Waste Connections ENVIRONM 3 3 B+ 95 0.70 2Weis Markets GROCERY 3 1 A 95 0.65 3

Average 3 2 B++ 97 0.66 3

Delivery Group Average 3 2 B++ 99 0.67 3

Source of Information: Value Line Investment Survey for Windows, January 2013

Comparable Earnings ApproachUsing Non-Utility Companies with

Timeliness of 2 & 3; Safety Rank of 1, 2 & 3; Financial Strength of B, B+, B++ & A;Price Stability of 95 to 100; Betas of .55 to .75; and Technical Rank of 2 & 3



Page 2 of 2

ProjectedCompany 2007 2008 2009 2010 2011 Average 2015-17

Altria Group 49.4% 122.0% 89.5% NMF NMF 87.0% NMFAmerisourceBergen 15.9% 17.3% 18.8% 21.6% 24.6% 19.6% 27.5%Berkley (W.R.) 20.6% 16.5% 10.2% 11.4% 7.7% 13.3% 12.5%Campbell Soup 59.5% 60.5% 105.9% 91.1% 77.8% 79.0% 58.0%Capitol Fed. Fin'l 3.7% 5.8% 7.0% 7.1% 3.3% 5.4% 4.5%Church & Dwight 15.6% 15.1% 15.5% 15.3% 15.9% 15.5% 17.0%Clorox Co. NMF - - NMF NMF - NMFDaVita Inc. 19.7% 19.2% 19.8% 22.8% 22.5% 20.8% 19.0%Dollar General - 3.8% 10.0% 15.5% 16.4% 11.4% 19.0%Erie Indemnity Co. 20.6% 18.0% 12.0% 17.8% 21.4% 18.0% 24.5%Haemonetics Corp. 11.4% 11.9% 12.5% 12.2% 10.7% 11.7% 12.0%Hershey Co. 81.3% 135.3% 69.3% 65.1% 76.4% 85.5% 52.5%Hormel Foods 15.8% 14.2% 16.1% 17.0% 17.8% 16.2% 16.0%Kellogg 43.7% 79.3% 53.3% 57.8% 69.9% 60.8% 33.5%Kroger Co. 24.0% 24.1% 23.2% 21.1% 30.0% 24.5% 23.5%Laboratory Corp. 29.4% 30.4% 25.3% 23.7% 25.8% 26.9% 20.0%Marsh & McLennan 6.9% NMF 9.2% 8.6% 16.2% 10.2% 20.0%People's United Fin'l 3.4% 2.7% 2.0% 1.6% 3.8% 2.7% 6.0%Philip Morris Int'l 39.1% NMF NMF NMF NMF 39.1% NMFQuest Diagnostics 16.7% 17.8% 18.3% 17.9% 19.7% 18.1% 16.0%Silgan Holdings 24.6% 25.1% 23.2% 26.1% 29.4% 25.7% 20.0%Stericycle Inc. 18.0% 22.8% 21.1% 20.4% 20.2% 20.5% 15.0%Verisk Analytics - - - - - - 37.0%Waste Connections 12.8% 8.2% 8.7% 10.5% 12.1% 10.5% 13.5%Weis Markets 7.1% 7.1% 9.1% 9.4% 10.1% 8.6% 9.0%

Average 27.4% 21.6%

Average (excluding values >20%) 12.4% 13.3%

NMF = no meaningful figure

Comparable Earnings ApproachFive -Year Average Historical Earned Returns

for Years 2007-2011 andProjected 3-5 Year Returns

STATE OF MICHIGAN




JOYLYN C. HOFFMAN MALUEG, CMA

FOR


June 7, 2013

- 1 -

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

JOYLYN C. HOFFMAN MALUEG, CMA PART I


A. My name is Joylyn C. Hoffman Malueg. My business address is Integrys Business 2

Support, LLC (“IBS”), 700 North Adams Street, P.O. Box 19001, Green Bay, WI 3

54307-9001. I am a Rate Case Consultant in the Regulatory Affairs Department of 4

Integrys Energy Group, Inc. (“Integrys”). Both IBS and Michigan Gas Utilities 5

Corporation (“MGUC”) are wholly-owned subsidiaries of Integrys. 6

7



10


A. I am a 1999 graduate of the University of Wisconsin – Green Bay where I received a 12

Bachelor of Science Degree in Mathematics with a Statistical emphasis. I received 13

my Master of Business Administration degree from Cardinal Stritch University, 14

Milwaukee, Wisconsin, in February 2006. I am also a Certified Management 15

Accountant (“CMA”) through the Institute of Management Accountants (“IMA”), 16

having received that professional designation in November 2009. 17

18

- 2 -

In March of 2001, I was hired by Wisconsin Public Service Corporation (“WPS Corp”) 1

as a Revenue Requirements Forecaster in the Rates and Economic Development 2

Department. In that position, I was primarily responsible for revenue requirements 3

and cost of service analyses pertaining to WPS Corp’s wholesale jurisdiction. In 4

October of 2003, my job title changed to Rate Analyst within the Regulatory Affairs 5

department. In that position, I worked primarily on revenue requirements analyses 6

for WPS Corp’s Michigan retail jurisdiction, as well as performing revenue 7

requirement analyses and cost of service studies for Upper Peninsula Power 8

Company (“UPPCO”). Since December of 2006, I have been a Rate Case 9

Consultant and my primary job duties include performing cost of service study 10

analyses for all regulated Integrys subsidiaries. I am also responsible for conducting 11

the revenue requirement analyses for WPS Corp’s Michigan retail electric and gas 12

jurisdictions. 13

14


A. Yes, I have. I have filed testimony on behalf of WPS Corp, UPPCO or MGUC before 16

the Michigan Public Service Commission (“the Commission”) in Case Nos. U-14410, 17

U-14745, U-15352, U-15549, U-15988, U-15990, U-16166, and U-16417. I have 18

filed testimony on behalf of WPS Corp before the Public Service Commission of 19

Wisconsin (“PSCW”) in rate case Docket Nos. 6690-UR-119, 6690-UR-120, 6690-20

UR-121, and 6690-UR-122, and before the Minnesota Public Utilities Commission 21

(“MPUC”) on behalf of Minnesota Energy Resources Corporation (“MERC”) in rate 22

case Docket Nos. G007,011/GR-08-835 and G007,11/GR-10-977. I have also filed 23

testimony before the Illinois Commerce Commission (“ICC”) on behalf of The 24

Peoples Gas Light and Coke Company (“PGL”) and North Shore Gas Company 25

(“NSG”) in rate case Docket Nos. 09-0166, 09-0167, 11-0280, 11-0281, 12-0512, 26

and 12-0511. In addition, I have participated in the preparation of various accounting 27

- 3 -

and filing exhibits for WPS Corp, UPPCO, MGUC, MERC, PGL and NSG for 1

presentation to the PSCW, MPSC, MPUC, Federal Energy Regulatory Commission 2

(“FERC”), and the ICC. 3

- 4 -

JOYLYN C. HOFFMAN MALUEG, CMA DIRECT TESTIMONY

PART II


A. The purpose of my pre-filed direct testimony is to discuss and sponsor the class cost 2

of service studies (“COSS”) I completed for MGUC for the 2014 projected test year 3

and the 2012 historic test year. 4

5


A. Yes, I am. I am sponsoring: 7

1. Exhibit A-6 (JCHM-1), Schedules F1.1 through F1.11, and 8

2. Exhibit A-16 (JCHM-2), Schedules F1.1 through F1.7. 9

10

These exhibits are the COSS prepared for MGUC, along with associated allocation 11

methodologies, supplemental analyses, and data. The following testimony explains 12

these studies. 13

14



17

Q. Please describe Exhibit A-6 (JCHM-1), Schedules F1.1 through F1.11. 18

A. Schedule F1.1 contains the MGUC 2014 Projected COSS - General Summary as 19

required by the Commission’s Orders dated December 23, 2008 and February 20, 20

2009 issued in Case No. U-15895. 21

22

Schedule F1.2 contains the MGUC 2014 Projected COSS - Detailed Summary. 23

24

- 5 -

Schedule F1.3 contains the MGUC 2014 Projected COSS - Individual Rate Schedule 1

Revenue Requirement and Rate Base Components. 2

3

Schedule F1.4 contains the MGUC 2014 Projected COSS – Consumption Costs by 4

Billing Unit. 5

6

Schedule F1.5 contains the MGUC 2014 Projected COSS - Allocation Factors. 7

8

Schedule F1.6 contains the MGUC Account 380: Average Cost per Service Line 9

Foot Analysis, based upon 2012 historic test year data. 10

11

Schedule F1.7 contains the MGUC Account 381: Cost per Meter Analysis, based 12

upon 2012 historic test year data. 13

14

Schedule F1.8 contains the MGUC 2014 Projected COSS - Classification & 15

Functionalization of MGUC Costs and Investment. 16

17

Schedule F1.9 contains the MGUC 2014 Projected COSS – Translation of 18

Distribution O&M FERC Accounts to Plant Accounts. 19

20

Schedule F1.10 contains the MGUC Transmission Mains Zero-Intercept Regression 21

Analysis for FERC Account 367, based upon 2012 historic test year data. 22

23

Schedule F1.11 contains the MGUC Distribution Mains Zero-Intercept Regression 24

Analysis for FERC Account 376, based upon 2012 historic test year data. 25

26

27

- 6 -

Q. Please describe Exhibit A-16 (JCHM-2), Schedules F1.1 through F1.7. 1

A. Schedule F1.1 contains the MGUC 2012 Historical COSS - General Summary as 2

required by the Commission’s Orders dated December 23, 2008 and February 20, 3

2009 issued in Case No. U-15895. 4

5

Schedule F1.2 contains the MGUC 2012 Historical COSS - Detailed Summary. 6

7

Schedule F1.3 contains the MGUC 2012 Historical COSS - Individual Rate Schedule 8

Revenue Requirement and Rate Base Components. 9

10

Schedule F1.4 contains the MGUC 2012 Historical COSS – Consumption Costs by 11

Billing Unit. 12

13

Schedule F1.5 contains the MGUC 2012 Historical COSS - Allocation Factors. 14

15

Schedule F1.6 contains the MGUC 2012 Historical COSS - Classification & 16

Functionalization of MGUC Costs and Investment. 17

18

Schedule F1.7 contains the MGUC 2010 COSS – Translation of Distribution O&M 19

FERC Accounts to Plant Accounts. 20

21 General Information 22

Q. What is the purpose of a COSS? 23

A. The purpose of a COSS is to identify the revenues, costs and profitability for each 24

rate schedule. The results of the COSS provide the data necessary to design cost-25

based rates using an embedded cost methodology. 26

27

28

- 7 -

Q. How should a COSS be performed? 1

A. Cost causation is the fundamental principle applicable to all cost studies for purposes 2

of allocating costs to rate schedules. The most important theoretical principle 3

underlying a COSS is that cost incurrence should follow historical embedded cost 4

causation. The costs that customers become responsible to pay should be those 5

costs that the particular customers caused the utility to incur because of the 6

characteristics of the customers’ usage of utility service. By performing a COSS in 7

this manner, it can then be used in determining how costs should be recovered from 8

rate schedules through rate design. 9

10

Q. Please explain the procedures used to develop the COSS shown in the various 11

Schedules of Exs. A-6 (JCHM-1) and A-16 (JCHM-2). 12

A. In general, preparing a COSS involves three major steps: 13

a. Cost functionalization, 14

b. Cost classification; and 15

c. Cost allocation 16

of the utility’s system costs to the rate schedules. 17

18

The first step, cost functionalization, identifies and separates plant and expenses into 19

specific categories based on their purpose and various characteristics of utility 20

operation. Typically, these plant and expenses are functionalized by the FERC 21

Uniform System of Accounts (“USOA”). These accounts group plant and expenses 22

into their various functions, which for MGUC includes Production (which incorporates 23

Storage related items), Transmission, Distribution, and Customer. 24

25

- 8 -

Step two, cost classification, further separates the functionalized plant and expenses 1

into the categories based upon how they are incurred. These classifications consist 2

of: 3

1. Commodity related, which can be further broken down into the 4 subcategories of: 5

6 a. Purchased Gas Cost, and 7

8 b. Gas Supply Acquisition Cost, 9

10 2. Demand, or capacity related, which can be further broken down into the 11

subcategories of: 12 13

a. Production demand, 14 15

b. Storage demand, and 16 17

c. Distribution demand, and 18 19

3. Customer related, which can be further broken down into the 20 subcategories of: 21

22 a. Customer, and 23

24 b. Enhanced Services. 25

26

Commodity related costs are those costs that vary with the throughput sold to, or 27

transported for, customers. For example, included in the COSS are commodity 28

related costs such as other gas supplies expense. However, when, as is the case 29

with MGUC, a gas utility’s cost of gas is recovered through a one-for-one 30

mechanism, very little of its remaining delivery service cost structure is commodity 31

related. 32

33

Demand related costs are incurred to service the peak demand of the system. 34

Examples of costs classified as demand include manufactured gas clean-up costs, 35

structures and improvements, measuring and regulation equipment, and a portion of 36

transmission and distribution mains. 37

38

- 9 -

Customer related costs are incurred for a customer to be attached to the distribution 1

system, meter any gas usage, and maintain the customer’s account. Customer 2

related costs are found to vary with the number of customers, regardless of the 3

customers’ gas consumption. Examples of costs classified to the customer 4

classification include distribution services, meters, regulators, a portion of 5

transmission and distribution mains, and customer billing and accounting. 6

7

The final step of preparing a COSS is allocation of each functionalized and classified 8

cost element to the rate schedules. Costs that are classified to the commodity cost 9

element are typically allocated to rate schedules using an allocation factor based 10

upon the rate schedules’ gas usage, or throughput. Costs that are classified to the 11

demand cost element are typically allocated to rate schedules using an allocation 12

factor based upon the rate schedules’ demand imposed upon the system during 13

specific peak days. Costs that are classified to the customer cost element are 14

typically allocated to rate schedules using an allocation factor based upon customer 15

counts and, in some instances, customer counts that are weighted to reflect, for 16

example, differences in metering costs amongst rate schedules. 17

18

Q. Please explain the considerations relied upon in determining the cost 19

allocation methodologies that are used to perform a COSS. 20

A. As stated earlier, in order to allocate costs within any COSS, the factors that cause 21

the costs to be incurred must be identified and understood. Additionally, the cost 22

analyst needs to develop data in a form that is compatible with, and supportive of, 23

rate design proposals. The availability of data for use in developing alternative cost 24

allocation factors is also a consideration. In evaluating any cost allocation 25

methodology, appropriate consideration should be given to whether it provides a 26

sound rationale or theoretical basis, whether the results reflect cost causation and 27

- 10 -

are representative of the costs of serving different types of customers, as well as the 1

stability of the results over time. 2

3

Q. What is the source of the cost data analyzed in MGUC’s COSS? 4

A. All cost of service data have been extracted from MGUC’s revenue requirements and 5

rate base contained in the instant filing as shown in Ms. De Cramer’s Exs. A-1 (KAD-6

1), A-2 (KAD-2), A-3 (KAD-3), and associated workpapers for the 2014 projected test 7

year; and Ms. De Cramer’s Exs. A-11 (KAD-7), A-12 (KAD-8), A-13 (KAD-9) and 8

associated workpapers for the 2012 historic test year. Where more detailed 9

information was required to perform various supplementary analyses related to 10

certain plant and expense elements, the data was either taken directly from MGUC’s 11

various software systems, or derived from the historical books and records of MGUC. 12

13

Q. Does the COSS allocate costs to the rate schedules as defined in present 14

rates? 15

A. The COSS submitted for both the 2012 historic test year and the 2014 projected test 16

year in this proceeding are based upon rates that are currently in effect, or present 17

rates as they were referred to above. All values in the COSS are allocated to each 18

rate schedule utilizing the allocation method described in the column titled “Allocation 19

Factor”. Direct assignment of values to the appropriate rate schedules was 20

conducted whenever possible, as recommended by the American Gas Association 21

(“AGA”) in their Fourth Edition of Gas Rate Fundamentals (1987) (“AGA Gas Rate 22

Fundamentals”), page 140. 23

24

Q. Please describe how you defined the rate schedules in MGUC’s COSS. 25

A. The rate schedules that were utilized in the COSS follow the rate schedules under 26

which MGUC currently provides retail service in Michigan. 27

- 11 -

1

The rate schedules shown in the MGUC COSS consist of the following: 2

1. Residential, which includes residential heating, general, and lighting, 3 4

2. Multi-Family, which is split into separate cost of service for Meter Classes 5 I, II, III and IV, 6

7 3. Small General Service, which includes commercial lighting, 8

9 4. Large General Service, 10

11 5. Transportation – TR-1, 12



17 8. Customer Choice – Residential, 18

19 9. Customer Choice – Small General Service, 20

21 10. Customer Choice – Large General Service, 22

23 11. Customer Choice – Multi-Family, which is split into separate cost of 24

service for Meter Classes I, II, III and IV, 25 26

12. Aggregated Transportation – Residential, 27 28

13. Aggregated Transportation – Small General Service, 29 30

14. Aggregated Transportation – Large General Service, and 31 32

15. Special Contract, which consists of one customer who is currently served 33 by MGUC under the terms of a special contract. This customer’s rates 34 cannot be changed in a general rate case proceeding; therefore, I show 35 them in a separate column solely to segregate their revenues and 36 associated costs. 37

38

Q. Did you make any changes to the classes of service included in the COSS you 39

prepared for the instant general rate case compared to the cost study 40

submitted in MGUC’s last general rate case proceeding in Case No. U-15990? 41

A. Yes, I made one change. Since MGUC’s last rate case in Case No. U-15990, there 42

have been a number of customers who have moved from taking service under the 43

sales rate schedule Multi-Family to taking service under Customer Choice – Multi-44

Family. Therefore, the addition of this choice rate schedule, which is split into 45

- 12 -

separate cost of service for Meter Classes I, II, III and IV, has been made to the cost 1

study. 2

3

Q. Please describe MGUC’s approach in the development of its COSS. 4

A. As stated earlier, when describing the general procedures for preparing a COSS, 5

MGUC’s COSS attempts to associate costs with customers based on cost causation. 6

In some cases, there can be a direct association of costs to customers based on 7

causation. For example, some plant costs such as investment in meters and 8

services can be directly associated with the number of customers. In other cases, 9

causation can be based on a direct relationship between costs and some parameter 10

that can be related to customers. An example of this is gas supply acquisition costs, 11

which has a direct relationship to customers’ sales. Therefore, gas supply 12

acquisition costs are allocated to customers based on sales. Other costs may have 13

relationships to customer parameters that are not direct, but are significantly 14

influenced by those parameters. Distribution system costs fall into this category. 15

16

Q. How does MGUC allocate distribution costs to customers? 17

A. In the case of distribution costs, MGUC has identified two significant cost causation 18

relationships. Some distribution costs are incurred in order for customers to simply 19

be connected to the distribution system. Other distribution costs are incurred due to 20

the level of demand of customers. 21

22

Some gas distribution demand related costs are influenced by the sizing of facilities 23

based on the coincident consumption of gas on the distribution facilities. These 24

costs are allocated based on the weighted group peak demand. An example of 25

these costs would be Accounts 378 and 379, measuring and regulating station 26

equipment. 27

- 13 -

1

Other demand related costs of gas distribution facilities, such as Account 376, gas 2

mains, are influenced by both the coincident group demand and connection of the 3

customer to the distribution system. In the COSS, these costs were allocated to rate 4

schedules on both a weighted group peak demand, as well as customer count basis. 5

6

Q. Were there any special analyses conducted for purposes of allocating 7

distribution costs and plant investment? 8

A. Yes, there were. Regarding MGUC’s major plant accounts, customer weighting 9

factors were developed to allocate the following distribution plant accounts: 10

1. Account 380: Services, and 11

2. Account 381: Meters. 12

13

MGUC has also performed minimum distribution system studies comprised of the 14

zero-intercept method which identify the smallest distribution gas mains that would 15

be used to connect customers to the distribution system regardless of their gas 16

usage or demand. The costs needed to support the minimum distribution system 17

have a relationship to the number of customers and are allocated on that basis. The 18

costs in excess of the minimum system are related to the demand of customers and 19

are, therefore, allocated based on the customers’ demands. 20

21

Q. Please continue with how MGUC allocates distribution costs to customers. 22

A. Specifically, distribution costs are allocated within the COSS based on the following 23

methods: 24

1. Accounts 302 & 303 Intangible Plant, 374 Land and Land Rights, 375 25 Structures and Improvements, 378 Measuring & Regulation Equipment – 26 General, and Account 379 Measuring & Regulation Equipment – Gate Station 27 were allocated based on the weighted peak demand allocator. 28

29 2. Account 376 Gas Distribution Mains utilized a zero-intercept method based 30

- 14 -

on a regression of cost per foot versus pipe diameter squared. This analysis 1 is shown in Exhibit A-6 (JCHM-1), Schedule F1.11. The regression analysis 2 provided a split of system gas mains costs that are attributable to fixed costs 3 and demand related costs, showing 54% of the costs are attributable to 4 minimum system; the remaining 46% are attributable to customer demand. 5 Each of these categories was allocated based on customer counts and 6 weighted peak demand, respectively. 7

8 3. Account 380 Services was allocated on a customer basis, using a weighting 9

factor of Average Cost Per Foot for Services, which was derived from service 10 installations, by associated meter size, to be performed in the historic year 11 ending December 31, 2012. 12

13 4. Account 381 Meters was allocated on a customer basis, using a weighting 14

factor of Cost Per Meter, which was based on actual plant investment as of 15 December 31, 2012, by rate schedule, as adjusted to current cost using the 16 Handy-Whitman Index. 17

18 5. Account 383 House Regulators was allocated based on customer counts. 19

20 6. Account 385 Industrial Metering & Regulating Station Equipment was 21

allocated based on the weighted peak demand of industrial sized customers 22 only. 23

24

Q. How does the COSS allocate distribution related Operation and Maintenance 25

(“O&M”) expenses? 26

A. In general, these expenses should be allocated in the same manner as how the 27

distribution plant investment costs are allocated, as stated above. A gas utility’s 28

distribution related O&M expenses generally are thought to support the utility’s 29

corresponding plant-in-service accounts. In order to allocate distribution O&M costs 30

in a similar manner as the distribution plant investment, a translation was performed 31

to convert the FERC O&M Distribution Accounts 870 through 894 to FERC Plant 32

Distribution Accounts 302/303, and 374 through 386. The computations involved in 33

this translation can be found in Exhibit A-6 (JCHM-1), Schedule F1.9 and ExhibitA-16 34

(JCHM-2), Schedule F1.7 for the projected 2014 test year and historic 2012 test 35

year, respectively. A summary of the translation can be found in the table below: 36

37

- 15 -

1

O&M Distribution Account Translated to: Distribution Plant Account

Account 870: Supervisory & Engineering

Accounts 302/303, and 374-386 on the basis of Distribution Plant Investment in Accounts 302/303, and 374-386

Account 871: Load Dispatch Account 880: Other Account 881: Rents Account 885: Supervisory & Engineering

Account 874: Mains & Services Expense

Accounts 376 and 380, on the basis of Distribution Plant Investment in Accounts 376 and 380, which are Mains and Services

Account 877: Measuring & Regulating Expense-Gate Station

Account 379, Measuring & Regulation Equipment-Gate Station

Account 878: Meter & House Regulators Accounts 381.0, 381.2, 381.3, 383 and 385, on the basis of Distribution Plant Investment in Accounts 381.0, 381.2, 381.3, 383 and 385 which are all Metering and Regulator related

Account 879: Customer Installations Account 893: Meter & House Regulators Account 886: Structures & Improvements Account 375: Structures & Improvements Account 889: Measuring & Regulating Expense-General

Account 378: Measuring & Regulation Equipment - General

Account 892: Services Account 380: Services

2

Q. How does MGUC allocate production costs and investment to each rate 3

schedule? 4

A. MGUC first classifies production costs and investment within the appropriate 5

categories of Commodity or Demand. The Commodity classification is further 6

detailed into sub-categories of Purchased Gas Cost or Gas Supply Acquisition, and 7

Demand classified production costs and investment is further detailed into sub-8

categories of either Production Demand or Storage Demand. 9

10

The only production costs that are classified to Purchased Gas Cost are the costs of 11

gas sold which are recovered via MGUC’s Gas Cost Recovery (“GCR”) plan. These 12

Purchased Gas Costs are either direct assigned to the rate schedules, or allocated to 13

the rate schedules based upon gas usage, or sales. 14

15

- 16 -

The only production costs that are classified to Production Demand are O&M 1

expenses relating to Manufactured Gas Plant Clean-up in the FERC Account Series 2

710-742. This Production Demand classified item is allocated to the rate schedules 3

based upon Weighted Peak Demand. 4

5

The production costs and investment that are classified to Storage Demand are 6

costs relating to Underground Storage in the FERC Account Series 350-357 and 7

814-842. These Storage Demand classified items are allocated to the rate 8

schedules based upon the Storage allocation methodology. 9

10

Any remaining production costs are classified to either Gas Supply Acquisition or 11

Production Demand, and are costs relating to Natural Gas Production & Gathering, 12

Non-GCR related Gas Purchases, and Other Gas Supplies Expense. These items 13

are then allocated to the rate schedules based upon the respective allocation 14

method: either gas usage, or sales, for Gas Supply Acquisition classified costs, or 15

weighted peak demand for Production Demand classified costs. 16

17

Q. How does MGUC allocate transmission costs and investment to each rate 18

schedule? 19

A. The majority of the investment that is functionalized to Transmission for MGUC are 20

related to transmission mains in Account 367, while the O&M costs functionalized to 21

Transmission are mainly non-transmission main items such as Operational 22

Supervision and Engineering, and Measuring and Regulating Stations and 23

Equipment. Given this, Transmission costs and investment related to transmission 24

mains, which are Accounts 367,856, and 863, are first classified to the demand and 25

customer classifications based upon a zero intercept regression analysis of cost per 26

foot of transmission main versus pipe diameter squared. The regression analysis 27

- 17 -

provided a percentage of the system transmission mains that are attributable to fixed 1

costs, which is 58%, and the remaining percentage, 42%, is assumed to be 2

attributable to customer demand. The fixed costs and demand related costs are then 3

allocated to the rate schedules based on throughput and weighted peak demand, 4

respectively. Classifying and allocating transmission costs in this manner is reflected 5

in the AGA Gas Rate Fundamentals, as discussed at pages 197 – 201, and as 6

shown within the tables presented on pages 138 and 142. 7

8

The investment and costs functionalized to Transmission that are not main related 9

were classified to demand and allocated to the rate schedules on the basis of 10

weighted peak demand. 11

12

Q. How does MGUC allocate customer costs to each rate schedule? 13

A. In general, customer costs are allocated based on total customer counts by rate 14

schedule. 15

16

Costs that could be directly related to transportation customers were identified and 17

allocated directly to those customers based on a specific transport customer 18

allocator. The allocator for transportation costs is shown on Exhibit A-6 (JCHM-1), 19

Schedule F1.5 for the 2014 projected test year, and Exhibit A-16 (JCHM-2), 20

Schedule F1.5 for the 2012 historic test year. 21

22

With respect to customer costs in Account 904 Uncollectibles, as well as Customer 23

Services costs in Accounts 907-910, the costs are allocated based on margin 24

revenue by rate schedule. 25

26

27

- 18 -

Q. How does MGUC allocate Administrative and General (“A&G”) costs to each 1

rate schedule? 2

A. First, a piece of Administrative and General (“A&G”) costs are directly allocated to 3

transportation customers based upon a proportional split of transport direct assigned 4

O&M Customer Accounts Expense to Total Distribution & Customer related O&M 5

Expense (excluding any direct assigned costs). Once the transportation direct 6

assigned piece of A&G is calculated, the remaining A&G is functionalized to 7

Production, Distribution, Transmission, Storage and Customer functions according to 8

Salaries and Wages, which can be found in Exhibit A-6 (JCHM-1), Schedule F1.5 for 9

the 2014 projected test year, and Exhibit A-16 (JCHM-2), Schedule F1.5 for the 2012 10

historic test year. 11

12

Next, the functionalized costs are classified to Commodity, Demand or Customer. 13

The Production function was further sub-categorized between Gas Supply 14

Acquisition and Production Demand based upon the percentage of Production O&M 15

costs, as shown on line 14 of page 5 of Exhibit A-6 (JCHM-1), Schedule F1.8 for the 16

2014 projected test year, and Exhibit A-16 (JCHM-2), Schedule F1.6 for the historic 17

2012 test year. The Distribution function was further sub-categorized between 18

Distribution Demand and Customer based upon the percentage of Distribution O&M 19

costs, as shown on line 36 of page 5 of Exhibit A-6 (JCHM-1), Schedule F1.8 for the 20

2014 projected test year, and Exhibit A-16 (JCHM-2), Schedule F1.6 for the historic 21

2012 test year. The Transmission function was further sub-categorized between 22

Distribution Demand and Customer based upon the percentage of Transmission 23

O&M costs, as shown on line 20 of page 5 of Exhibit A-6 (JCHM-1), Schedule F1.8 24

for the 2014 projected test year, and Exhibit A-16 (JCHM-2), Schedule F1.6 for the 25

historic 2012 test year. 26

27

- 19 -

Once functionalized, the costs are then allocated to rate schedules based upon the 1

respective allocation methodology. Gas Supply Acquisition and Production Demand 2

related A&G were allocated to the rate schedules based upon the Sales and 3

Weighted Peak Demand allocation methods, respectively. Storage related A&G was 4

allocated to the rate schedules based upon the Storage allocation method. 5

Distribution Demand related A&G was allocated to the rate schedules based upon 6

the Distribution O&M Demand Related allocation method, which is created on pages 7

5 and 6 of Exhibit A-6 (JCHM-1), Schedule F1.2 for the 2014 projected test year, and 8

pages 5 and 6 of Exhibit A-16 (JCHM-2), Schedule F1.2 for the 2012 historic test 9

year. Customer related A&G was allocated to the rate schedules based upon the 10

Customer O&M allocation method, which is created on pages 5 and 6 of Exhibit A-6 11

(JCHM-1), Schedule F1.2 for the 2014 projected test year, and pages 5 and 6 of 12

Exhibit A-16 (JCHM-2), Schedule F1.2 for the 2012 historic test year. The direct-13

assigned portion of A&G that is attributable to transportation customers were 14

allocated based upon the Transportation Customers allocation methodology. 15

16

Q. Please describe the remaining components of the MGUC COSS that have 17

unique allocators and why these unique allocators are appropriate. 18

A. The remaining components of the cost of service which have unique allocators are 19

as follows: 20

1. Income Taxes, Taxes other than Income Taxes (“TOTIT”) associated with 21 Real Estate & Property, Franchise Tax Fees, State Unitary Fees, Use Tax, 22 Unauthorized Insurance Tax, and Federal Excise Tax, and Miscellaneous 23 Revenues in Account 493 and Illinois Tax Fees in Account 495 were 24 allocated to the rate schedules based upon a rate base allocator, which was 25 created on pages 1 and 2 of Exhibit A-6 (JCHM-1), Schedule F1.2 for the 26 2014 projected test year and pages 1 and 2 of Exhibit A-16 (JCHM-2), 27 Schedule F1.2 for the 2012 historic test year. The Rate Base allocator was 28 utilized because these items follow cost-causation theory from various Rate 29 Base investments. 30

31 2. TOTIT relating to Unemployment Compensation, IBS Payroll Tax, and 32

Retirement Benefits are allocated to the rate schedules based upon a 33 salaries and wages allocator, which can be found in Exhibit A-6 (JCHM-1), 34

- 20 -

Schedule F1.5 for 2014 projected test year, and Exhibit A-16 (JCHM-2), 1 Schedule F1.5 for the 2012 historic test year. The Salaries & Wages 2 allocator was utilized because these TOTIT items are payroll related and, 3 therefore, follow cost-causation theory. 4

5 3. Miscellaneous Revenues in Account 487 attributable to Late Payments is 6

allocated on the basis of Margin Revenue. The Margin Revenue allocator 7 was utilized because the amounts booked to this account are based upon a 8 percentage of customers’ total unpaid bill balances. 9

10 4. Miscellaneous Revenues in Account 495 attributable to the Uncollectible 11

Expense Tracking Mechanism is direct assigned to the rate schedules. 12 13

5. Miscellaneous Revenues in Account 495 attributable to Revenue Decoupling 14 is partially allocated on the basis of Throughput of three separate customer 15 categories: Residential, Small General Services and Small Multi-Family, and 16 Large Multi-Family. The respective allocation methodologies are: Thru-put – 17 Residential, Thru-put – Small GS & MF, and Thru-put – Large MF. The 18 respective Throughput allocation methodologies of these three separate 19 customer categorizes were utilized because Decoupling Revenues are 20 attributable to the Revenue Stability Mechanism, which is based upon a 21 function of gas use and the credit/surcharge of the Revenue Stability 22 Mechanism is recovered through rate design based upon usage. The 23 remaining portion of the Revenue Decoupling is direct assigned based upon 24 the reconciliation process. 25

26

Natural Gas COSS for the 2012 Projected Test Year 27 Q. Please describe Exhibit A-6 (JCHM-1), Schedule F1.1. 28

A. As required by the Commission’s Orders dated December 23, 2008 and February 29

20, 2009 issued in Case No. U-15895, Schedule F1.1 is a summary of the COSS 30

results for MGUC for the 2014 projected test year. Each page summarizes the 31

various components of the operating income and rate base to the rate schedules. 32

Additionally, each page provides the revenue deficiency and revenue requirement by 33

rate schedule. Schedule F1.1 consists of 4 pages. 34

35

Q. Please describe Exhibit A-6 (JCHM-1), Schedule F1.2. 36

A. Schedule F1.2 is a detailed summary of the COSS results for MGUC for the 2014 37

projected test year. Within Schedule F1.2, each rate schedule is presented in a side-38

by-side, columnar format with the details of each component of operating income 39

and rate base presented, and the allocation methodology that was used to allocate 40

- 21 -

the costs and plant investment are provided in Column [B] of each page. Schedule 1

F1.2 consists of 20 pages. 2

3

Pages 1 and 2 summarize the various components of the operating income and rate 4

base to the rate schedules served by MGUC for the 2014 projected test year. Line 5

40 of pages 1 and 2 shows the Rate of Return resulting from the projected results of 6

operation. Line 52 of pages 1 and 2 shows the revenue deficiency by rate schedule 7

based on a proposed rate of return of 10.75%, which is supported in the pre-filed 8

direct testimony of Mr. Paul R. Moul. Line 56 of pages 1 and 2 shows the revenue 9

deficiency by rate schedule excluding cost of gas. Pages 1 and 2 also include the 10

creation of the allocation methodology for Rate Base, which is used throughout other 11

pages of the COSS. 12

13

Pages 3 and 4 contain the Operating Revenues for MGUC based on the rates 14

authorized in MGUC’s last general rate case in Case No. U-15990. Pages 3 and 4 15

also include the creation of the allocation methodology for Margin Revenue, which is 16

used throughout other pages of the COSS. 17

18

Pages 5 and 6 contain the Allocation of O&M Expense, including A&G expense, for 19

MGUC. Pages 5 and 6 also include the creation of the Distribution O&M Demand 20

Related and Customer O&M allocation methodologies, which are used to allocate 21

certain A&G expenses to the rate schedules, as shown on the same pages. 22

23

Pages 7 and 8 contain the Allocation of Depreciation Expense, including 24

Amortization Expense, with General expenses apportioned, for MGUC. For the 2014 25

projected test year, there was no Amortization Expense. 26

27

- 22 -

Pages 9 and 10 contain the Allocation of Taxes Other Than Income Taxes for 1

MGUC. 2

3

Pages 11 and 12 contain the Allocation of Other Income and Adjustments, both 4

Before and After Income Taxes, for MGUC. For the 2014 projected test year, there 5

were no Other Income and Adjustments. 6

7

Pages 13 and 14 contain the Allocation of the rate base component Plant-in-Service, 8

with General investment apportioned, for MGUC. 9

10

Pages 15 and 16 contain the Allocation of the rate base component Accumulated 11

Depreciation – Straight Line, with General investment apportioned, for MGUC. 12

13

Pages 17 and 18 contain the Allocation of the rate base component Construction 14

Work in Progress (“CWIP”), with General investment apportioned, for MGUC. 15

16

Pages 19 and 20 contain the Allocation of Other Rate Base Components, such as 17

Gas Stored Underground, Materials & Supplies, Working Capital, Prepayments, 18

Cash & Bank Balances, and Accrued Taxes for MGUC. 19

20


A. Schedule F1.3 contains the functionalized and classified revenue requirements and 22

rate base for each of the rate schedules in MGUC’s service territory. There is one 23

page of information for each rate schedule or special contract customer. Schedule 24


26

27

- 23 -


A. Schedule F1.4 consists of three pages and contains the cost of service for MGUC 2

rate schedules by consumption unit, or billing unit. 3

4

Page 1 of Schedule F1.4 is a summary of all the billing unit costs by rate schedule, 5

broken down into the billing units of Fixed Charge, Enhanced Administrative Charge, 6

Local Volumetric Rate, Storage Rate, and Gas Supply Acquisition Rate. The column 7

titled Total Monthly Fixed Charge is the summation of the Fixed Charge and 8

Enhanced Administrative Charge for each rate schedule. The column titled Total Mcf 9

Rate is the summation of the Local Volumetric Rate, the Storage Rate, and Gas 10

Supply Acquisition Rate for each rate schedule. 11

12

Page 2 of Schedule F1.4 shows the creation of the Local Volumetric Rate, the 13

Storage Rate, and Gas Supply Acquisition Rate for each of the rate schedules. The 14

Mcf Throughput and Sales values shown in Columns [B] and [G], respectively, were 15

taken from Exhibit A-6 (JCHM-1), Schedule F1.5, pages 1 and 2. The Demand 16

Costs, Storage Costs, and Gas Supply Acquisition Costs shown in Columns [C], [E], 17

and [H], respectively, were taken from the respective columns of Exhibit A-6 (JCHM-18

1), Schedule F1.3 on each of the pages for the rate schedules. 19

20

Page 3 of Schedule F1.4 shows the creation of the Fixed Charge and Enhanced 21

Administrative Charge for each of the rate schedules. Customer Counts were taken 22

from Exhibit A-6 (JCHM-1), Schedule F1.5, pages 3 and 4. The Customer Costs and 23

Enhanced Administrative Costs shown in Columns [C] and [E], respectively, were 24

taken from the respective columns of Exhibit A-6 (JCHM-1), Schedule F1.3 on each 25

of the pages for the rate schedules. 26

27

- 24 -


A. Schedule F1.5 contains a summary of the majority of the allocation methodologies 2

used within the COSS shown in my Exhibit A-6 (JCHM-1), Schedule F1.2. Schedule 3


5

Pages 1 and 2 show the development of the following allocation factors: 6

1. The Group Demand allocation, which consists of the monthly peak of 7 each rate schedule (group), including transportation, to simulate 8 distribution system peaking (based on the highest one month of demand 9 for each group). 10

11 2. The Weighted Peak Demand allocation, which consists of the group 12

demand for each rate schedule, including transportation, and weighting 13 those demands based on annual Mcf throughput, 14

15 3. The Sales allocation, which is the sales of all customers, not including 16

transportation sales, 17 18

4. The Mcf Throughput allocation, which is the sales of all customers, 19 including transportation sales, 20

21 5. The Throughput – Residential allocation, which is the throughput of all 22

residential customers, including customer choice and aggregated 23 transportation, 24

25 6. The Throughput – Small General Service and Small Multi-Family 26

allocation, which is the throughput of all small general service and small 27 multi-family customers (i.e. classes I and II), including customer choice 28 and aggregated transportation, 29

30 7. The Throughput – Large Multi-Family allocation, which is the throughput 31

of all large multi-family customers (i.e. classes III and IV), including 32 customer choice, 33

34 8. The Storage allocation, which is based on a 50/50 weighting of group 35

peak demand and storage capacity. The storage capacity is equal to the 36 sum of the transportation customer’s Authorized Tolerance Limits 37 (“ATL’s”) and the amount that can be withdrawn for GCR customers, 38 including customer choice and aggregated transport. 39

40 9. The Customer allocation factor, which is based on total annual bill counts. 41

42 43 Pages 3 and 4 show the development of the following allocation factors: 44

1. The allocation factor for Account 380: Services, which is based on 45 average bill counts and utilizes an Average Cost Per Foot for Services 46 weighting factor, 47

- 25 -

1 2. The allocation factor for Account 381: Meters, which is based on average 2

customer counts and utilizes a Cost Per Customer for Meters weighting 3 factor, 4

5 3. Transport Customers allocation factor, which is based on the total yearly 6

customer counts for transportation customers, 7 8

4. The allocation factor for Account 385, which is based on the Weighted 9 Peak Demand allocator for Industrial size customers, 10

11 5. The Salaries and Wages functional allocation factor, and 12

13 6. The Salaries and Wages rate schedule allocation factor. 14

15 16 Q. Can you please explain the significance of Column [M] labeled “Source or 17

Allocation Factor” on each page of Schedule F1.5 of Exhibit A-6 (JCHM-1)? 18

A. Column [M], labeled “Source or Allocation Factor”, represents the name that was 19

given to each of the specific allocators created within Schedule F1.5. Each of these 20

names shown in the “Source or Allocation Factor” column is what is used throughout 21

the COSS in Exhibit A-6 (JCHM-1), Schedule F1.2 when referencing the allocation 22

methodology that was used to allocate costs to the rate schedules. 23

24


A. Schedule F1.6 consists of one page and contains the analysis behind the creation of 26

the Average Cost per Foot per Customer for Services weighting factor utilized in the 27

creation of the Services allocation factor. The data is based upon estimated service 28

project costs by meter class for the 2012 historical year. 29

30


A. Schedule F1.7 consists of one page and contains the analysis behind the creation of 32

the Cost per Customer for Meters weighting factor utilized in the creation of the 33

Meters allocation factor. The data is based upon actual plant investment by rate 34

schedule as of December 31, 2012 adjusted to current cost utilizing Handy Whitman 35

- 26 -

data. 1

2


A. Schedule F1.8 contains the classification and functionalization of MGUC data for the 4

2014 projected test year. Schedule F1.8 consists of five pages. 5

6

Page 1 contains a detailed breakdown of the classification and functionalization of 7

Plant-in-Service, with General investment apportioned. This page also portrays the 8

classification and functionalization of transmission and distribution mains to the 9

Customer and Demand functions based upon the results of the zero-intercept 10

regression analyses portrayed in Exhibit A-6 (JCHM-1), Schedule F1.10 and 11

Schedule F1.11, respectively. All of the classified and functionalized values shown 12

on this page are utilized and allocated to the rate schedules as shown in Exhibit A-6 13

(JCHM-1), Schedule F1.2, pages 13 and 14. Also shown on Page 1, line 45, is the 14

percentage breakdown of Transmission and Distribution Plant-in-Service classified to 15

Demand and Customer. These percentages are utilized to classify the Materials & 16

Supplies component of Rate Base, as shown on Exhibit A-6 (JCHM-1), Schedule 17

F1.2, pages 19 and 20. 18

19


Accumulated Depreciation – Straight Line, with General investment apportioned. 21

This page also portrays the classification and functionalization of transmission and 22

distribution mains to the Customer and Demand functions based upon the results of 23

the zero-intercept regression analyses portrayed in Exhibit A-6 (JCHM-1), Schedule 24

F1.10 and Schedule F1.11, respectively. All of the classified and functionalized 25

values shown on this page are utilized and allocated to the rate schedules as shown 26

in Exhibit A-6 (JCHM-1), Schedule F1.2, pages 15 and 16. 27

- 27 -

1


CWIP, with General investment apportioned. This page also portrays the 3

classification and functionalization of transmission and distribution mains to the 4





(JCHM-1), Schedule F1.2, pages 17 and 18. 9

10


Depreciation Expense, with General expense apportioned. This page also portrays 12

the classification and functionalization of transmission and distribution mains to the 13





(JCHM-1), Schedule F1.2, pages 7 and 8. 18

19


O&M Expense, including A&G expense. This page also portrays the classification 21

and functionalization of transmission and distribution mains to the Customer and 22

Demand functions based upon the results of the zero-intercept regression analyses 23

portrayed in Exhibit A-6 (JCHM-1), Schedule F1.10 and Schedule F1.11, 24

respectively. All of the classified and functionalized values shown on this page are 25

utilized and allocated to the rate schedules as shown in Exhibit A-6 (JCHM-1), 26

Schedule F1.2, pages 5 and 6. Additionally, the classification percentages of the 27

- 28 -

Production function to sub-category classifications of Gas Supply Acquisition and 1

Production Demand, and the Transmission, Distribution and Customer functions to 2

the Demand and Customer classifications are created on this page. These 3

percentages are utilized to classify A&G Expense on the same page, as shown on 4

line 49. 5

6


A. Schedule F1.9 consists of one page and contains the computations behind the 8

translation of O&M FERC Distribution Accounts 870 through 894 to FERC Plant 9

Distribution Accounts 302/303, and 374 through 386 for MGUC for the 2014 10


12

Q. Please describe Schedule F1.10 and Schedule F1.11 of Exhibit A-6 (JCHM-1). 13

A. Schedule F1.10 contains the detail of the Transmission Mains Zero-Intercept study 14

and consists of 8 pages. Schedule F1.11 contains the detail of the Distribution 15

Mains Zero-Intercept study and consists of 20 pages. When conducting the Zero-16

Intercept studies, any outliers that were found were removed from the analysis. 17

18

Natural Gas COSS for the 2012 Historic Test Year 19 Q. Please describe Exhibit A-16 (JCHM-2), Schedule F1.1. 20

A. As required by the Commission’s Orders dated December 23, 2010 and February 21

20, 2009 issued in Case No. U-15895, Schedule F1.1 is a summary of the COSS 22

results for MGUC for the 2012 historic test year. Each page summarizes the various 23

components of operating income and rate base to rate schedules. Additionally, the 24

pages present the revenue deficiency and revenue requirement by rate schedule. 25

Schedule F1.1 consists of 4 pages. 26

27

28

- 29 -


A. Schedule F1.2 is a detailed summary of the COSS results for MGUC for the 2012 2

historic test year. Within Schedule F1.2, each rate schedule is presented in a side-3

by-side, columnar format, the details of each component of operating income and 4

rate base are presented, and the allocation methodology that was used to allocate 5

the costs and plant investment are provided in Column [B] of each page. Schedule 6


8

Q. Do the 20 pages of the 2012 historic test year COSS shown in Schedule F1.2 of 9

Exhibit A-16 (JCHM-2) for MGUC follow the same layout as presented in 10

Schedule F1.2 of Exhibit A-6 (JCHM-1) for the 2014 projected test year? 11

A. Yes, they do. The only differences would be on Page 1, Line 40, which shows the 12

Index of Return resulting from historical operations. Also, Line 52 of pages 1 and 2 13

shows the revenue deficiency by rate schedule based upon the required rate of 14

return of 10.75%, which was authorized in MGUC’s last general rate case in Case 15

No. U-15990. 16

17


A. Schedule F1.3 contains a functionalized revenue requirement and rate base 19

allocation for each of the rate schedules in MGUC’s service territory for the 2012 20

historic test year. There is one page of information for each rate schedule and 21

special contract customer. Schedule F1.3 consists of 21 pages. 22

23

Q. Do the 21 pages of functionalized revenue requirement and rate base 24

allocation for each of the rate schedules for the 2012 historic test year shown 25

in schedule F1.3 of Exhibit A-16 (JCHM-2) for MGUC follow the same layout as 26

presented in Schedule F1.3 of Exhibit A-6 (JCHM-1) for the 2014 projected test 27

- 30 -

year? 1

A. Yes, they do. 2

3


A. Schedule F1.4 contains the cost of service for MGUC rate schedules by consumption 5

unit or billing unit for the 2012 historic test year, and consists of three pages. 6

7

Q. Do the three pages of consumption units for the 2012 historic test year shown 8

in Schedule F1.4 of Exhibit A-16 (JCHM-2) for MGUC follow the same layout as 9


year? 11

A. Yes, they do. 12

13


A. Schedule F1.5 contains the creation of allocation factors utilized in MGUC’s COSS 15

for the 2012 historic test year, and consists of four pages. 16

17

Q. Do the four pages of allocation factors the 2012 historic test year COSS shown 18

in Schedule F1.5 of Exhibit A-16 (JCHM-2) for MGUC follow the same layout as 19


year? 21

A. Yes, they do. 22

23


A. Schedule F1.6 contains the classification and functionalization of MGUC data for the 25

2012 historic test year. Schedule F1.6 consists of five pages. 26

27

- 31 -

Q. Do the five pages of classified and functionalized 2012 historic test year data 1

shown in Schedule F1.6 of Exhibit A-16 (JCHM-2) for MGUC follow the same 2

layout as presented in Schedule F1.8 of Exhibit A-6 (JCHM-1) for the 2014 3

projected test year? 4

A. Yes, they do. 5

6


A. Schedule F1.7 consists of one page and contains the computations behind the 8

translation of O&M FERC Distribution Accounts 870 through 894 to FERC Plant 9

Distribution Accounts 302/303, and 374 through 386 for MGUC for the 2012 historic 10

test year. 11

12

Conclusion 13 Q. Please summarize the results of the COSS for MGUC for the 2014 projected 14

test year. 15

A. As stated by MGUC witness, Ms. Katherine A. De Cramer, in her pre-filed direct 16

testimony, MGUC, overall, is showing a revenue deficiency (cost recovery shortfall) 17

of $8,036,820, or 6.01%, in the 2014 projected test year, which includes the cost of 18

gas. Removing the cost of gas, the revenue deficiency is 12.95% for MGUC, overall. 19

The results of the COSS with respect to revenue deficiency at present rates by rate 20

schedule based on the requested revenue requirement for MGUC are summarized 21

below: 22

- 32 -

1

MGUC Rate Schedule

Revenue Deficiency / (Surplus) $

(including gas

costs)

% (including gas costs)

% (excluding gas costs)

Residential 8,751,504 9.96% 25.78%

Multi-Family - Class I 9,463 6.52% 22.84%

Multi-Family - Class II -37,215 -4.91% -17.46%

Multi-Family - Class III -11,001 -5.38% -21.66%

Multi-Family - Class IV -15,691 -5.41% -23.63%

Small General Service -510,449 -2.33% -7.65%

Large General Service -134,284 -7.13% -34.94%

Transport - TR-1 -974,447 -40.45% -40.45%

Transport - TR-2 -314,274 -12.02% -12.02%

Transport - TR-3 101,830 6.05% 6.05%

Customer Choice - Residential 1,655,240 22.30% 22.30%

Customer Choice - Small GS -461,068 -10.41% -10.41%

Customer Choice - Large GS n/a n/a n/a

Customer Choice - Multi-Family - Class I 3,462 39.75% 39.75%

Customer Choice - Multi-Family - Class II -8,094 -24.24% -24.24%

Customer Choice - Multi-Family - Class III n/a n/a n/a

Customer Choice - Multi-Family - Class IV -18,310 -26.75% -26.75%

Agg Transport - Residential 22,494 157.89% 157.89%

Agg Transport - Small GS 107,813 5.83% 5.83%

Agg Transport - Large GS -16,271 -38.35% -38.35%

Special Contract -113,882 -90.84% -92.01% 2

Q. In your opinion, does the MGUC COSS provide a reasonable basis for 3

establishing rates in this case? 4

A. Yes, it does. The COSS for MGUC is a reasonable estimate of revenue 5

requirements by rate schedule, given the total revenue requirement, and supports 6

- 33 -

the rates requested in this case, as explained further in the pre-filed direct testimony 1

of Mr. David J. Tyler. 2

3


A. Yes, it does. 5

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Case No. U-17273 Witness: J.C. Hoffman Malueg

Exhibit A-6 (JCHM-1) Schedule F1.1

Page 1 of 4

Michigan Public Service CommissionMichigan Gas Utilities CorporationProjected Cost of Service Allocation StudyProjected Test Year Ending December 31, 2014

Individual Rate Schedule Detail

(A) (B) (C) (D) (E) (F) (G) (H) (I)

MF-I MF-II MF-III MF-IV GS-Small TOTALLINE SUMMARY OF OPERATING INCOME, Multi-Family Multi-Family Multi-Family Multi-Family TOTAL General Service SMALLNO. RATE BASE AND RATE OF RETURN Residential Class I Class II Class III Class IV RESIDENTIAL Small COMMERCIAL

1 Operating Revenues:2 Tariffed Revenues 87,828,772 145,170 757,241 204,544 290,241 89,225,968 21,946,622 21,946,6223 Other Revenues 732,584 1,016 4,489 1,120 1,548 740,757 134,551 134,5514 Total Operating Revenues: 88,561,356 146,186 761,730 205,664 291,789 89,966,725 22,081,173 22,081,17356 Operating Expense:7 Operation & Maintenance: Cost of Gas 53,882,128 103,746 544,109 153,745 223,832 54,907,560 15,276,696 15,276,6968 Operation & Maintenance: Non-Cost of Gas 24,137,298 27,379 86,380 18,055 22,089 24,291,200 3,019,255 3,019,2559 Depreciation Expense - S/L 6,062,371 7,191 23,591 5,276 6,649 6,105,078 822,433 822,43310 Taxes other than Income Tax 2,462,247 3,320 13,733 3,460 4,706 2,487,466 459,390 459,39011 LESS: Income & Other Adj's Before Income Tax 0 0 0 0 0 0 0 012 Income Tax 1,556,040 2,025 8,193 2,041 2,720 1,571,019 287,971 287,97113 ITC Credit 0 0 0 0 0 0 0 014 LESS: Income & Other Adj's After Income Tax 0 0 0 0 0 0 0 015 Total Operating Expense 88,100,085 143,660 676,006 182,578 259,996 89,362,325 19,865,746 19,865,7461617 NET OPERATING INCOME (Return) 461,271 2,525 85,724 23,086 31,793 604,400 2,215,427 2,215,42718 AFUDC Allowance 0 0 0 0 0 0 0 019 Income Tax Affect of Int. Allow for Ratemaking (2,744) (4) (14) (4) (5) (2,771) (508) (508)20 ADJUSTED NET OPERATING INCOME 458,526 2,522 85,710 23,083 31,788 601,629 2,214,919 2,214,919212223 RATE BASE:24 Utility Plant in Service 208,636,928 254,122 928,687 220,540 275,033 210,315,311 33,454,764 33,454,76425 Accumulated Depreciation - S/L (111,713,373) (137,277) (496,543) (117,470) (149,073) (112,613,737) (17,425,024) (17,425,024)26 Construction Work in Progress 0 0 0 0 0 0 0 027 Net Plant in Service 96,923,556 116,845 432,144 103,070 125,960 97,701,574 16,029,741 16,029,7412829 Gas Stored Underground: 6,852,380 12,517 65,352 18,129 27,626 6,976,004 1,940,740 1,940,74030 Fuel Stock 0 0 0 0 0 0 0 031 Working Capital Allowance 13,471,866 23,756 124,883 34,196 53,770 13,708,470 3,848,267 3,848,26732 Materials & Supplies: 333,374 391 1,131 229 305 335,430 35,600 35,60033 Other - Deferred Taxes (M&S / CWIP) 0 0 0 0 0 0 0 034 Prepayments 218,901 421 2,346 662 966 223,297 65,989 65,98935 Cash & Bank Balances 78,489 152 845 238 348 80,072 23,710 23,71036 Property, Payroll & Income Taxes Accrued: (1,107,959) (2,128) (11,853) (3,347) (4,883) (1,130,169) (333,692) (333,692)37 TOTAL RATE BASE 116,770,608 151,953 614,848 153,178 204,091 117,894,677 21,610,355 21,610,355383940 PERCENT RATE OF RETURN 0.3950% 1.6620% 13.9424% 15.0717% 15.5780% 0.3950% 10.2517% 10.2517%4142 Required Rate of Return 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020%4344 Required Return 7,475,645 9,728 39,362 9,806 13,066 7,547,608 1,383,493 1,383,49345 (Required Return % * Rate Base)46 Return Income Deficiency 7,017,119 7,206 (46,348) (13,276) (18,723) 6,945,978 (831,426) (831,426) 47 (Required Ret - Adj Operating Income)48 Income Tax Rate 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 4950 Additional Income Tax on Return Def. 1,734,385 2,257 9,132 2,275 3,031 1,751,081 320,977 320,977 51 (Income Deficiency * Tax Factor)52 Revenue Deficiency 8,751,504 9,463 (37,215) (11,001) (15,691) 8,697,059 (510,449) (510,449) 5354 Revenue Deficiency % 9.96% 6.52% -4.91% -5.38% -5.41% 9.75% -2.33% -2.33%55 (Revenue Def / Tariffed Revenues)56 Revenue Deficiency % (Without Cost of Gas) 25.78% 22.84% -17.46% -21.66% -23.63% 25.34% -7.65% -7.65%57 (Distribution Margin Only)

May not cross-check due to Rounding



Page 2 of 4



(A) (B) (C) (D) (E)

GS-Large TOTAL TOTALLINE SUMMARY OF OPERATING INCOME, General Service LARGE Special SPECIALNO. RATE BASE AND RATE OF RETURN Large COMMERCIAL Contract CONTRACT

1 Operating Revenues:2 Tariffed Revenues 1,883,203 1,883,203 125,365 125,3653 Other Revenues 9,797 9,797 966 9664 Total Operating Revenues: 1,893,000 1,893,000 126,331 126,33156 Operating Expense:7 Operation & Maintenance: Cost of Gas 1,498,862 1,498,862 1,597 1,5978 Operation & Maintenance: Non-Cost of Gas 106,699 106,699 10,334 10,3349 Depreciation Expense - S/L 28,864 28,864 90 9010 Taxes other than Income Tax 23,316 23,316 71 7111 LESS: Income & Other Adj's Before Income Tax 0 0 0 012 Income Tax 14,591 14,591 52 5213 ITC Credit 0 0 0 014 LESS: Income & Other Adj's After Income Tax 0 0 0 015 Total Operating Expense 1,672,331 1,672,331 12,143 12,1431617 NET OPERATING INCOME (Return) 220,669 220,669 114,188 114,18818 AFUDC Allowance 0 0 0 019 Income Tax Affect of Int. Allow for Ratemaking (26) (26) (0) (0)20 ADJUSTED NET OPERATING INCOME 220,643 220,643 114,188 114,188212223 RATE BASE:24 Utility Plant in Service 1,253,381 1,253,381 3,678 3,67825 Accumulated Depreciation - S/L (678,126) (678,126) (1,880) (1,880)26 Construction Work in Progress 0 0 0 027 Net Plant in Service 575,255 575,255 1,799 1,7992829 Gas Stored Underground: 187,619 187,619 561 56130 Fuel Stock 0 0 0 031 Working Capital Allowance 345,596 345,596 1,533 1,53332 Materials & Supplies: 1,154 1,154 3 333 Other - Deferred Taxes (M&S / CWIP) 0 0 0 034 Prepayments 3,921 3,921 4 435 Cash & Bank Balances 1,380 1,380 1 136 Property, Payroll & Income Taxes Accrued: (20,002) (20,002) (24) (24)37 TOTAL RATE BASE 1,094,924 1,094,924 3,877 3,877383940 PERCENT RATE OF RETURN 20.1538% 20.1538% 2945.6378% 2945.6378%4142 Required Rate of Return 6.4020% 6.4020% 6.4020% 6.4020%4344 Required Return 70,097 70,097 248 24845 (Required Return % * Rate Base)46 Return Income Deficiency (150,546) (150,546) (113,940) (113,940) 47 (Required Ret - Adj Operating Income)48 Income Tax Rate 0.6367 0.6367 0.6367 0.6367 4950 Additional Income Tax on Return Def. 16,263 16,263 58 58 51 (Income Deficiency * Tax Factor)52 Revenue Deficiency (134,284) (134,284) (113,882) (113,882) 5354 Revenue Deficiency % -7.13% -7.13% -90.84% -90.84%55 (Revenue Def / Tariffed Revenues)56 Revenue Deficiency % (Without Cost of Gas) -34.94% -34.94% -92.01% -92.01%57 (Distribution Margin Only)




Page 3 of 4



(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (O)Customer Customer Customer Customer

Customer Customer Customer Choice Choice Choice Choice Aggregated Aggregated AggregatedLINE SUMMARY OF OPERATING INCOME, TR-1 TR-2 TR-3 Choice Choice Choice Multi-Family Multi-Family Multi-Family Multi-Family Transport Transport Transport TOTALNO. RATE BASE AND RATE OF RETURN Transport Transport Transport Residential GS - Small GS - Large Class I Class II Class III Class IV Residential GS - Small GS - Large TRANSPORT

1 Operating Revenues:2 Tariffed Revenues 2,408,779 2,614,173 1,683,100 7,422,621 4,431,105 0 8,708 33,386 0 68,455 14,247 1,849,311 42,424 20,576,3093 Other Revenues 18,829 20,285 13,028 106,710 43,331 0 138 354 0 549 172 15,199 333 218,9284 Total Operating Revenues: 2,427,608 2,634,458 1,696,128 7,529,331 4,474,436 0 8,846 33,740 0 69,004 14,419 1,864,510 42,757 20,795,23756 Operating Expense:7 Operation & Maintenance: Cost of Gas 0 0 0 0 0 0 0 0 0 0 0 0 0 08 Operation & Maintenance: Non-Cost of Gas 633,730 860,088 618,992 5,078,086 1,872,580 0 6,856 13,400 0 20,036 29,755 945,895 11,145 10,090,5639 Depreciation Expense - S/L 180,303 319,438 252,280 1,301,821 538,894 0 1,761 3,423 0 6,772 2,030 213,720 2,744 2,823,18510 Taxes other than Income Tax 128,038 228,935 183,576 524,755 300,698 0 692 1,678 0 4,785 974 158,087 2,317 1,534,53411 LESS: Income & Other Adj's Before Income Tax 0 0 0 0 0 0 0 0 0 0 0 0 0 012 Income Tax 73,850 131,739 107,376 329,436 188,016 0 433 1,032 0 2,760 600 94,589 1,485 931,31813 ITC Credit 0 0 0 0 0 0 0 0 0 0 0 0 0 014 LESS: Income & Other Adj's After Income Tax 0 0 0 0 0 0 0 0 0 0 0 0 0 015 Total Operating Expense 1,015,921 1,540,200 1,162,224 7,234,098 2,900,188 0 9,742 19,534 0 34,353 33,358 1,412,292 17,692 15,379,6001617 NET OPERATING INCOME (Return) 1,411,687 1,094,258 533,904 295,233 1,574,247 0 (896) 14,206 0 34,652 (18,940) 452,219 25,066 5,415,63718 AFUDC Allowance 0 0 0 0 0 0 0 0 0 0 0 0 0 019 Income Tax Affect of Int. Allow for Ratemaking (130) (232) (189) (581) (332) 0 (1) (2) 0 (5) (1) (167) (3) (1,643)20 ADJUSTED NET OPERATING INCOME 1,411,557 1,094,026 533,715 294,652 1,573,916 0 (897) 14,204 0 34,647 (18,941) 452,052 25,063 5,413,994212223 RATE BASE:24 Utility Plant in Service 7,658,875 13,830,688 11,227,761 44,361,999 21,859,630 0 58,604 125,972 0 279,904 72,424 8,815,745 118,821 108,410,42325 Accumulated Depreciation - S/L (4,196,678) (7,612,045) (6,186,660) (23,850,180) (11,401,535) 0 (31,714) (67,256) 0 (151,795) (39,021) (4,758,516) (64,034) (58,359,433)26 Construction Work in Progress 0 0 0 0 0 0 0 0 0 0 0 0 0 027 Net Plant in Service 3,462,197 6,218,642 5,041,102 20,511,820 10,458,095 0 26,890 58,716 0 128,108 33,404 4,057,230 54,787 50,050,9902829 Gas Stored Underground: 504,691 873,062 699,016 1,464,178 1,273,063 0 1,914 6,490 0 28,030 3,972 997,893 19,282 5,871,59130 Fuel Stock 0 0 0 0 0 0 0 0 0 0 0 0 0 031 Working Capital Allowance 1,664,210 2,955,404 2,441,856 2,849,034 2,515,606 0 3,832 12,895 0 54,328 8,021 2,143,406 38,644 14,687,23732 Materials & Supplies: 8,093 14,278 10,975 72,724 23,506 0 101 178 0 311 108 9,647 107 140,02833 Other - Deferred Taxes (M&S / CWIP) 0 0 0 0 0 0 0 0 0 0 0 0 0 034 Prepayments 26,675 48,200 37,263 47,496 43,518 0 59 220 0 986 122 29,579 358 234,47535 Cash & Bank Balances 9,688 17,518 13,531 17,039 15,639 0 21 79 0 355 43 10,579 125 84,61836 Property, Payroll & Income Taxes Accrued: (133,598) (240,922) (185,897) (240,321) (220,035) 0 (301) (1,112) 0 (4,983) (617) (150,014) (1,835) (1,179,636)37 TOTAL RATE BASE 5,541,956 9,886,182 8,057,845 24,721,970 14,109,392 0 32,516 77,465 0 207,135 45,053 7,098,319 111,469 69,889,303383940 PERCENT RATE OF RETURN 25.4727% 11.0686% 6.6259% 1.1942% 11.1574% -2.7565% 18.3386% 16.7291% -42.0387% 6.3708% 22.4868% 7.7489%4142 Required Rate of Return 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020% 6.4020%4344 Required Return 354,796 632,913 515,863 1,582,699 903,282 0 2,082 4,959 0 13,261 2,884 454,434 7,136 4,474,30845 (Required Return % * Rate Base)46 Return Income Deficiency (1,056,761) (461,113) (17,852) 1,288,046 (670,634) - 2,979 (9,245) - (21,386) 21,825 2,382 (17,927) (939,687) 47 (Required Ret - Adj Operating Income)48 Income Tax Rate 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 0.6367 4950 Additional Income Tax on Return Def. 82,314 146,839 119,683 367,194 209,566 0 483 1,151 0 3,077 669 105,431 1,656 1,038,06151 (Income Deficiency * Tax Factor)52 Revenue Deficiency (974,447) (314,274) 101,830 1,655,240 (461,068) - 3,462 (8,094) - (18,310) 22,494 107,813 (16,271) 98,374 5354 Revenue Deficiency % -40.45% -12.02% 6.05% 22.30% -10.41% 39.75% -24.24% -26.75% 157.89% 5.83% -38.35% 0.48%55 (Revenue Def / Tariffed Revenues)56 Revenue Deficiency % (Without Cost of Gas) -40.45% -12.02% 6.05% 22.30% -10.41% 39.75% -24.24% -26.75% 157.89% 5.83% -38.35% 0.48%57 (Distribution Margin Only)




Page 4 of 4

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Page 1 of 20

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Page 2 of 20

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Page 3 of 20

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1994

%

May

not

cro

ss-c

heck

due

to R

ound

ing



Page 4 of 20

Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

OP

ER

ATIO

N &

MAI

NT

EN

ANC

E(A

)(B

)(C

)(D

)(E

)(F

)(G

)(H

)(I)

(J)

(K)

(L)

(N)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

Res

iden

tial

Mul

ti-Fa

mily

- C

lass

IM

ulti-

Fam

ily -

Cla

ss II

Mul

ti-Fa

mily

- C

lass

III

Mul

ti-Fa

mily

- C

lass

IV

Sm

all G

ener

al

Ser

vice

Larg

e G

ener

al

Ser

vice

Tra

nspo

rt - T

R-1

Tra

nspo

rt - T

R-2

Tra

nspo

rt - T

R-3

1P

rodu

ctio

n:2

P

urch

ased

Gas

Cos

t - C

OG

Sal

es71

,684

,716

53,8

82,1

2810

3,74

654

4,10

915

3,74

522

3,83

215

,276

,696

1,49

8,86

20

00

3

Gas

Sup

ply

Acqu

isiti

onS

ales

509,

495

382,

964

737

3,86

71,

093

1,59

110

8,57

810

,653

00

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d78

6,43

432

5,27

162

63,

500

989

1,44

098

,263

5,71

840

,146

72,5

8256

,044

5

Sto

rage

Cos

tS

tora

ge66

4,84

430

4,19

455

62,

901

805

1,22

686

,154

8,32

922

,404

38,7

5731

,031

6

Tot

al P

rodu

ctio

n73

,645

,489

54,8

94,5

5710

5,66

555

4,37

815

6,63

122

8,08

915

,569

,692

1,52

3,56

262

,551

111,

339

87,0

757 8

T

rans

mis

sion

9

Min

imum

Sys

tem

- T

hrou

ghpu

t Pie

ceM

CF

Thr

ough

put

33,4

9112

,275

2412

435

513,

480

341

2,03

34,

335

4,17

510

D

eman

d R

elat

ed S

yste

mW

eigh

ted

Pea

k D

eman

d31

2,68

312

9,32

624

91,

392

393

572

39,0

692,

273

15,9

6228

,858

22,2

8311

T

otal

Tra

nsm

issi

on34

6,17

414

1,60

127

31,

515

428

623

42,5

492,

615

17,9

9533

,193

26,4

5812 13

Dis

tribu

tion:

1430

2/30

3W

eigh

ted

Pea

k D

eman

d5,

672

2,34

65

257

1070

941

290

523

404

1537

4W

eigh

ted

Pea

k D

eman

d6,

118

2,53

05

278

1176

444

312

565

436

1637

5W

eigh

ted

Pea

k D

eman

d6,

410

2,65

15

298

1280

147

327

592

457

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d1,

879,

513

777,

370

1,49

78,

364

2,36

33,

441

234,

842

13,6

6595

,946

173,

464

133,

940

1837

6 (F

ixed

Cos

t)C

usto

mer

2,21

9,09

31,

670,

174

1,66

42,

770

226

144

101,

437

221

1,49

652

193

1937

7M

CF

Thr

ough

put

00

00

00

00

00

020

378

Wei

ghte

d P

eak

Dem

and

178,

122

73,6

7214

279

322

432

622

,256

1,29

59,

093

16,4

3912

,694

2137

9W

eigh

ted

Pea

k D

eman

d13

3,38

655

,169

106

594

168

244

16,6

6697

06,

809

12,3

109,

506

2238

0S

ervi

ces

2,24

2,14

61,

694,

823

1,68

82,

652

216

137

97,1

2421

21,

928

671

120

2338

1M

eter

s2,

127,

857

1,15

0,23

174

55,

640

1,60

553

345

2,92

31,

010

9,02

23,

120

438

2438

2M

eter

s0

00

00

00

00

00

2538

3C

usto

mer

888,

284

668,

556

666

1,10

990

5740

,604

8959

920

837

2638

5Ac

ct 3

85 D

eman

d33

,557

00

00

00

1,09

67,

698

13,9

1710

,746

27

Tot

al D

istri

butio

n9,

720,

156

6,09

7,52

26,

522

22,0

024,

915

4,91

696

8,12

518

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133,

519

222,

331

168,

871

28 29C

usto

mer

Acc

ount

s:30

Al

loca

ble

Cus

tom

er8,

833,

261

6,64

8,24

86,

622

11,0

2589

957

140

3,77

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15,

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2,07

337

231

D

irect

Tra

nspo

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rans

port

Cus

t27

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30

00

00

00

44,3

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,433

2,77

032

C

usto

mer

- Ac

ct 9

04 A

lloca

ble

Mar

gin

Rev

enue

1,91

6,68

41,

048,

205

1,27

96,

581

1,56

92,

051

205,

954

11,8

6874

,378

80,7

2151

,971

33

Tot

al C

usto

mer

Acc

ount

s:11

,024

,178

7,69

6,45

47,

901

17,6

062,

468

2,62

260

9,73

012

,749

124,

652

98,2

2655

,113

34 35C

usto

mer

Ser

vice

s:M

argi

n R

even

ue70

1,93

338

3,87

646

82,

410

574

751

75,4

254,

346

27,2

3929

,562

19,0

3336

Cus

tom

er S

ales

:D

irect

00

00

00

00

00

037

Tot

al C

usto

mer

:11

,726

,111

8,08

0,33

08,

369

20,0

163,

042

3,37

368

5,15

517

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151,

891

127,

788

74,1

4638 39 40

Allo

c %

of D

istri

butio

n D

eman

d O

&M

41

(n

ot in

clud

ing

Dire

ct A

lloca

ted)

:D

ist O

&M

Dem

and

Rel

ated

100.

00%

40.7

4%0.

08%

0.44

%0.

12%

0.18

%12

.31%

0.77

%5.

37%

9.71

%7.

50%

42Al

loc

% o

f Cus

tom

er O

&M

(not

Dire

ct A

lloca

ted)

:C

usto

mer

O&

M10

0.00

%70

.56%

0.07

%0.

17%

0.03

%0.

03%

5.98

%0.

15%

0.94

%0.

98%

0.62

%43 44

Adm

inis

trativ

e &

Gen

eral

:45

P

urch

ased

Gas

Cos

tS

ales

00

00

00

00

00

046

G

as S

uppl

y Ac

quis

ition

Cos

tS

ales

282,

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212,

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408

2,14

160

588

160

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5,89

80

00

47

Pro

duct

ion

Dem

and

Wei

ghte

d P

eak

Dem

and

435,

376

180,

072

347

1,93

854

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754

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3,16

522

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8231

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48

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rage

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tS

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2,10

811

9,92

621

91,

144

317

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33,9

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8,83

315

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3449

D

istri

butio

n D

eman

dD

ist O

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Dem

and

Rel

ated

2,01

8,83

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2,50

01,

584

8,85

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3,64

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8,47

515

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108,

445

196,

061

151,

389

50

Cus

tom

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mer

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,588

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7,47

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67,

738

18,5

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3,11

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015

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51

Tra

nspo

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loca

ble

Tra

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291

00

00

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801

52

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otal

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inis

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d G

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8,80

5,41

610

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32,5

786,

783

8,92

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43,5

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7,77

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Tot

al O

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aint

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9,20

2,76

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630,

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921

18,2

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521,

605,

560

633,

730

860,

088

618,

992

May

not

cro

ss-c

heck

due

to R

ound

ing



Page 5 of 20

Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

OP

ER

ATIO

N &

MAI

NT

EN

ANC

E(A

)(B

)(C

)

LIN

E

NO

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ES

CR

IPT

ION

ALLO

CAT

ION

FAC

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RC

OR

PO

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E

TO

TAL

1P

rodu

ctio

n:2

P

urch

ased

Gas

Cos

t - C

OG

Sal

es71

,684

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3

Gas

Sup

ply

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509,

495

4

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and

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786,

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9

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tem

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hrou

ghpu

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Thr

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put

33,4

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d R

elat

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2,68

311

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6,17

412 13

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tion:

1430

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1537

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118

1637

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410

1737

6 (D

eman

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ted

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879,

513

1837

6 (F

ixed

Cos

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mer

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9,09

319

377

MC

F T

hrou

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2037

8W

eigh

ted

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k D

eman

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8,12

221

379

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d P

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and

133,

386

2238

0S

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623

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7,85

724

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025

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385

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and

33,5

5727

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otal

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tribu

tion

9,72

0,15

628 29

Cus

tom

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30

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cabl

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mer

8,83

3,26

131

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nspo

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port

Cus

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4,23

332

C

usto

mer

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ct 9

04 A

lloca

ble

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gin

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enue

1,91

6,68

433

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otal

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tom

er A

ccou

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11,0

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7834 35

Cus

tom

er S

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Mar

gin

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701,

933

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11,7

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1138 39 40

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c %

of D

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n D

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d O

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41

(n

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clud

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and

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100.

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47

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and

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and

435,

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48

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2,01

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10,5

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6951

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9,20

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7

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Page 6 of 20

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Page 7 of 20

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R-2

Tra

nspo

rt - T

R-3

1B

EFO

RE

TAX

AD

JUST

MEN

TS:

2G

ain/

(Los

s) -

Sal

e of

Util

ity P

rope

rtyR

ate

Bas

e0

00

00

00

00

00

3T

OT

AL O

TH

ER

AD

JUS

TS

00

00

00

00

00

04 5 6

AFT

ER T

AX

AD

JUST

MEN

TS:

7T

ax A

mor

tizat

ions

(409

)R

ate

Bas

e0

00

00

00

00

00

8T

ax A

mor

tizat

ions

(419

/426

/431

)R

ate

Bas

e0

00

00

00

00

00

9T

OT

AL O

TH

ER

AD

JUS

TS

00

00

00

00

00

0

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

OT

HE

R IN

CO

ME

& A

DJU

ST

S(A

)(B

)(C

)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

1B

EFO

RE

TAX

AD

JUST

MEN

TS:

2G

ain/

(Los

s) -

Sal

e of

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ity P

rope

rtyR

ate

Bas

e0

3T

OT

AL O

TH

ER

AD

JUS

TS

04 5 6

AFT

ER T

AX

AD

JUST

MEN

TS:

7T

ax A

mor

tizat

ions

(409

)R

ate

Bas

e0

8T

ax A

mor

tizat

ions

(419

/426

/431

)R

ate

Bas

e0

9T

OT

AL O

TH

ER

AD

JUS

TS

0

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)(O

)

Cus

tom

er C

hoic

e -

Res

iden

tial

Cus

tom

er C

hoic

e -

Sm

all G

SC

usto

mer

Cho

ice

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rge

GS

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IC

usto

mer

Cho

ice

- M

ulti-

Fam

ily II

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

III

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IVAg

g T

rans

port

- R

esid

entia

lAg

g T

rans

port

- S

mal

l GS

Agg

Tra

nspo

rt -

Larg

e G

SS

peci

al C

ontra

ct

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

0

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

RAT

E B

ASE

CO

MP

ON

EN

T -

PLA

NT

IN S

ER

VIC

E(A

)(B

)(C

)(D

)(E

)(F

)(G

)(H

)(I)

(J)

(K)

(L)

(N)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

Res

iden

tial

Mul

ti-Fa

mily

- C

lass

IM

ulti-

Fam

ily -

Cla

ss II

Mul

ti-Fa

mily

- C

lass

III

Mul

ti-Fa

mily

- C

lass

IV

Sm

all G

ener

al

Ser

vice

Larg

e G

ener

al

Ser

vice

Tra

nspo

rt - T

R-1

Tra

nspo

rt - T

R-2

Tra

nspo

rt - T

R-3

1G

AS P

LAN

T:

2

Pro

duct

ion:

3

Pur

chas

ed G

as C

ost

Sal

es0

00

00

00

00

00

4

Pro

duct

ion

Dem

and

Wei

ghte

d P

eak

Dem

and

2,36

5,43

097

8,34

71,

884

10,5

272,

974

4,33

029

5,55

617

,198

120,

751

218,

310

168,

568

5

Sto

rage

Cos

tS

tora

ge17

,211

,746

7,87

5,09

114

,386

75,1

0620

,834

31,7

502,

230,

394

215,

621

580,

016

1,00

3,36

680

3,34

46

T

otal

Pro

duct

ion

19,5

77,1

768,

853,

438

16,2

6985

,633

23,8

0936

,080

2,52

5,95

023

2,81

970

0,76

81,

221,

676

971,

912

7 8

Tra

nsm

issi

on9

M

inim

um S

yste

m -

Thr

ough

put P

iece

MC

F T

hrou

ghpu

t23

,586

,665

8,64

4,99

916

,645

87,2

9824

,667

35,9

122,

451,

036

240,

482

1,43

1,58

73,

052,

659

2,94

0,42

710

D

eman

d R

elat

ed S

yste

mW

eigh

ted

Pea

k D

eman

d30

,753

,432

12,7

19,6

8124

,491

136,

861

38,6

7256

,301

3,84

2,58

222

3,59

41,

569,

914

2,83

8,29

42,

191,

587

11

Tot

al T

rans

mis

sion

54,3

40,0

9721

,364

,680

41,1

3622

4,15

963

,339

92,2

136,

293,

618

464,

076

3,00

1,50

15,

890,

953

5,13

2,01

412 13

D

istri

butio

n14

302/

303

Wei

ghte

d P

eak

Dem

and

320,

446

132,

537

255

1,42

640

358

740

,039

2,33

016

,358

29,5

7522

,836

1537

4W

eigh

ted

Pea

k D

eman

d34

5,65

314

2,96

327

51,

538

435

633

43,1

892,

513

17,6

4531

,901

24,6

3216

375

Wei

ghte

d P

eak

Dem

and

362,

159

149,

790

288

1,61

245

566

345

,251

2,63

318

,488

33,4

2425

,809

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d61

,903

,775

25,6

03,5

2649

,298

275,

488

77,8

4311

3,32

87,

734,

757

450,

075

3,16

0,09

05,

713,

220

4,41

1,45

818

376

(Fix

ed C

ost)

Cus

tom

er73

,088

,183

55,0

08,9

4854

,790

91,2

197,

440

4,72

83,

340,

921

7,29

349

,256

17,1

523,

079

1937

7M

CF

Thr

ough

put

00

00

00

00

00

020

378

Wei

ghte

d P

eak

Dem

and

5,86

3,90

82,

425,

324

4,67

026

,096

7,37

410

,735

732,

684

42,6

3429

9,34

354

1,19

241

7,88

121

379

Wei

ghte

d P

eak

Dem

and

67,6

8527

,995

5430

185

124

8,45

749

23,

455

6,24

74,

823

2238

0S

ervi

ces

80,7

73,6

9661

,056

,291

60,8

1495

,533

7,79

24,

951

3,49

8,89

37,

638

69,4

5624

,186

4,34

123

381

Met

ers

39,6

27,2

6621

,420

,859

13,8

7210

5,03

529

,882

9,92

18,

434,

831

18,8

1116

8,01

558

,113

8,16

324

382

Met

ers

00

00

00

00

00

025

383

Cus

tom

er16

,542

,584

12,4

50,5

7812

,401

20,6

461,

684

1,07

075

6,17

51,

651

11,1

493,

882

697

2638

5Ac

ct 3

85 D

eman

d62

4,93

00

00

00

020

,417

143,

351

259,

169

200,

117

27

Tot

al D

istri

butio

n27

9,52

0,28

517

8,41

8,81

119

6,71

761

8,89

513

3,39

214

6,74

024

,635

,197

556,

486

3,95

6,60

66,

718,

059

5,12

3,83

628 29

C

usto

mer

Cus

tom

er0

00

00

00

00

00

30 31T

otal

Pla

nt in

Ser

vice

353,

437,

558

208,

636,

928

254,

122

928,

687

220,

540

275,

033

33,4

54,7

641,

253,

381

7,65

8,87

513

,830

,688

11,2

27,7

61

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

RAT

E B

ASE

CO

MP

ON

EN

T -

PLA

NT

IN S

ER

VIC

E(A

)(B

)(C

)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

1G

AS P

LAN

T:

2

Pro

duct

ion:

3

Pur

chas

ed G

as C

ost

Sal

es0

4

Pro

duct

ion

Dem

and

Wei

ghte

d P

eak

Dem

and

2,36

5,43

05

S

tora

ge C

ost

Sto

rage

17,2

11,7

466

T

otal

Pro

duct

ion

19,5

77,1

767 8

T

rans

mis

sion

9

Min

imum

Sys

tem

- T

hrou

ghpu

t Pie

ceM

CF

Thr

ough

put

23,5

86,6

6510

D

eman

d R

elat

ed S

yste

mW

eigh

ted

Pea

k D

eman

d30

,753

,432

11

Tot

al T

rans

mis

sion

54,3

40,0

9712 13

D

istri

butio

n14

302/

303

Wei

ghte

d P

eak

Dem

and

320,

446

1537

4W

eigh

ted

Pea

k D

eman

d34

5,65

316

375

Wei

ghte

d P

eak

Dem

and

362,

159

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d61

,903

,775

1837

6 (F

ixed

Cos

t)C

usto

mer

73,0

88,1

8319

377

MC

F T

hrou

ghpu

t0

2037

8W

eigh

ted

Pea

k D

eman

d5,

863,

908

2137

9W

eigh

ted

Pea

k D

eman

d67

,685

2238

0S

ervi

ces

80,7

73,6

9623

381

Met

ers

39,6

27,2

6624

382

Met

ers

025

383

Cus

tom

er16

,542

,584

2638

5Ac

ct 3

85 D

eman

d62

4,93

027

T

otal

Dis

tribu

tion

279,

520,

285

28 29

Cus

tom

erC

usto

mer

030 31

Tot

al P

lant

in S

ervi

ce35

3,43

7,55

8

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)(O

)

Cus

tom

er C

hoic

e -

Res

iden

tial

Cus

tom

er C

hoic

e -

Sm

all G

SC

usto

mer

Cho

ice

- La

rge

GS

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IC

usto

mer

Cho

ice

- M

ulti-

Fam

ily II

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

III

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IVAg

g T

rans

port

- R

esid

entia

lAg

g T

rans

port

- S

mal

l GS

Agg

Tra

nspo

rt -

Larg

e G

SS

peci

al C

ontra

ct

00

00

00

00

00

021

2,38

519

4,94

10

265

985

04,

422

543

131,

864

1,56

118

1,68

2,70

51,

463,

066

02,

199

7,45

80

32,2

134,

565

1,14

6,82

822

,159

644

1,89

5,09

01,

658,

007

02,

465

8,44

40

36,6

345,

108

1,27

8,69

223

,720

662

1,87

6,70

81,

616,

639

02,

346

8,17

00

36,6

684,

799

1,09

3,54

221

,826

256

2,76

1,26

42,

534,

466

03,

451

12,8

080

57,4

857,

061

1,71

4,38

720

,294

238

4,63

7,97

24,

151,

105

05,

797

20,9

780

94,1

5311

,860

2,80

7,92

942

,120

495

28,7

7226

,409

036

133

059

974

17,8

6421

12

31,0

3528

,486

039

144

064

679

19,2

6922

83

32,5

1729

,846

041

151

067

783

20,1

8923

93

5,55

8,16

65,

101,

643

06,

947

25,7

810

115,

712

14,2

133,

450,

900

40,8

4948

012

,013

,719

2,20

8,61

40

17,1

5223

,309

04,

838

14,9

5321

9,01

41,

319

440

00

00

00

00

00

052

6,50

448

3,25

90

658

2,44

20

10,9

611,

346

326,

891

3,86

945

6,07

75,

578

08

280

127

163,

773

451

13,3

34,4

332,

313,

046

019

,037

24,4

110

5,06

616

,597

229,

370

1,38

246

13,

578,

559

5,35

3,74

50

2,54

314

,875

09,

395

4,71

239

2,28

42,

686

966

00

00

00

00

00

02,

719,

153

499,

892

03,

882

5,27

60

1,09

53,

384

49,5

7129

910

00

00

00

00

00

1,85

322

37,8

28,9

3716

,050

,518

050

,342

96,5

510

149,

116

55,4

574,

729,

125

52,9

812,

521

00

00

00

00

00

0

44,3

61,9

9921

,859

,630

058

,604

125,

972

027

9,90

472

,424

8,81

5,74

511

8,82

13,

678

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

RAT

E B

ASE

CO

MP

ON

EN

T -

DE

PR

EC

IAT

ION

RE

SE

RVE

- S

/L(A

)(B

)(C

)(D

)(E

)(F

)(G

)(H

)(I)

(J)

(K)

(L)

(N)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

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OR

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TO

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Res

iden

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- C

lass

IM

ulti-

Fam

ily -

Cla

ss II

Mul

ti-Fa

mily

- C

lass

III

Mul

ti-Fa

mily

- C

lass

IV

Sm

all G

ener

al

Ser

vice

Larg

e G

ener

al

Ser

vice

Tra

nspo

rt - T

R-1

Tra

nspo

rt - T

R-2

Tra

nspo

rt - T

R-3

1D

EP

RE

CIA

TIO

N R

ES

ER

VE -

S/L

:2

P

rodu

ctio

n:3

P

urch

ased

Gas

Cos

tS

ales

00

00

00

00

00

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d(1

,265

,721

)(5

23,5

05)

(1,0

08)

(5,6

33)

(1,5

92)

(2,3

17)

(158

,149

)(9

,202

)(6

4,61

3)(1

16,8

16)

(90,

199)

5

Sto

rage

Cos

tS

tora

ge(8

,189

,880

)(3

,747

,212

)(6

,845

)(3

5,73

8)(9

,914

)(1

5,10

7)(1

,061

,290

)(1

02,5

99)

(275

,990

)(4

77,4

32)

(382

,256

)6

T

otal

Pro

duct

ion

(9,4

55,6

01)

(4,2

70,7

16)

(7,8

53)

(41,

371)

(11,

505)

(17,

425)

(1,2

19,4

40)

(111

,802

)(3

40,6

03)

(594

,248

)(4

72,4

55)

7 8

Tra

nsm

issi

on9

M

inim

um S

yste

m -

Thr

ough

put P

iece

MC

F T

hrou

ghpu

t(1

3,20

2,81

7)(4

,839

,104

)(9

,317

)(4

8,86

6)(1

3,80

8)(2

0,10

2)(1

,371

,986

)(1

34,6

11)

(801

,342

)(1

,708

,749

)(1

,645

,927

)10

D

eman

d R

elat

ed S

yste

mW

eigh

ted

Pea

k D

eman

d(1

5,63

6,66

1)(6

,467

,355

)(1

2,45

2)(6

9,58

7)(1

9,66

3)(2

8,62

6)(1

,953

,771

)(1

13,6

87)

(798

,227

)(1

,443

,138

)(1

,114

,318

)11

T

otal

Tra

nsm

issi

on(2

8,83

9,47

8)(1

1,30

6,45

9)(2

1,77

0)(1

18,4

53)

(33,

470)

(48,

728)

(3,3

25,7

57)

(248

,299

)(1

,599

,569

)(3

,151

,887

)(2

,760

,244

)12 13

D

istri

butio

n14

302/

303

Wei

ghte

d P

eak

Dem

and

(308

,981

)(1

27,7

95)

(246

)(1

,375

)(3

89)

(566

)(3

8,60

7)(2

,246

)(1

5,77

3)(2

8,51

6)(2

2,01

9)15

374

Wei

ghte

d P

eak

Dem

and

(34,

895)

(14,

433)

(28)

(155

)(4

4)(6

4)(4

,360

)(2

54)

(1,7

81)

(3,2

20)

(2,4

87)

1637

5W

eigh

ted

Pea

k D

eman

d(2

40,0

75)

(99,

295)

(191

)(1

,068

)(3

02)

(440

)(2

9,99

7)(1

,745

)(1

2,25

5)(2

2,15

7)(1

7,10

8)17

376

(Dem

and)

Wei

ghte

d P

eak

Dem

and

(35,

478,

047)

(14,

673,

792)

(28,

253)

(157

,887

)(4

4,61

3)(6

4,95

0)(4

,432

,914

)(2

57,9

45)

(1,8

11,0

98)

(3,2

74,3

38)

(2,5

28,2

78)

1837

6 (F

ixed

Cos

t)C

usto

mer

(41,

888,

011)

(31,

526,

511)

(31,

401)

(52,

279)

(4,2

64)

(2,7

10)

(1,9

14,7

36)

(4,1

80)

(28,

230)

(9,8

30)

(1,7

64)

1937

7M

CF

Thr

ough

put

00

00

00

00

00

020

378

Wei

ghte

d P

eak

Dem

and

(3,6

03,2

40)

(1,4

90,3

07)

(2,8

69)

(16,

035)

(4,5

31)

(6,5

97)

(450

,218

)(2

6,19

8)(1

83,9

40)

(332

,550

)(2

56,7

78)

2137

9W

eigh

ted

Pea

k D

eman

d3,

374

1,39

63

154

642

225

172

311

240

2238

0S

ervi

ces

(44,

651,

434)

(33,

751,

717)

(33,

618)

(52,

810)

(4,3

07)

(2,7

37)

(1,9

34,1

76)

(4,2

22)

(38,

395)

(13,

370)

(2,4

00)

2338

1M

eter

s(1

7,76

1,01

5)(9

,600

,869

)(6

,217

)(4

7,07

7)(1

3,39

3)(4

,446

)(3

,780

,507

)(8

,431

)(7

5,30

4)(2

6,04

6)(3

,659

)24

382

Met

ers

00

00

00

00

00

025

383

Cus

tom

er(6

,447

,819

)(4

,852

,874

)(4

,834

)(8

,047

)(6

56)

(417

)(2

94,7

35)

(643

)(4

,345

)(1

,513

)(2

72)

2638

5Ac

ct 3

85 D

eman

d(3

72,9

79)

00

00

00

(12,

185)

(85,

557)

(154

,681

)(1

19,4

37)

27

Tot

al D

istri

butio

n(1

50,7

83,1

20)

(96,

136,

197)

(107

,655

)(3

36,7

20)

(72,

495)

(82,

920)

(12,

879,

827)

(318

,026

)(2

,256

,507

)(3

,865

,910

)(2

,953

,960

)28 29

C

usto

mer

Cus

tom

er0

00

00

00

00

00

30 31T

otal

Dep

reci

atio

n R

eser

ve -

Stra

ight

Lin

e:(1

89,0

78,1

99)

(111

,713

,373

)(1

37,2

77)

(496

,543

)(1

17,4

70)

(149

,073

)(1

7,42

5,02

4)(6

78,1

26)

(4,1

96,6

78)

(7,6

12,0

45)

(6,1

86,6

60)

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

RAT

E B

ASE

CO

MP

ON

EN

T -

DE

PR

EC

IAT

ION

RE

SE

RVE

- S

/L(A

)(B

)(C

)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

1D

EP

RE

CIA

TIO

N R

ES

ER

VE -

S/L

:2

P

rodu

ctio

n:3

P

urch

ased

Gas

Cos

tS

ales

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d(1

,265

,721

)5

S

tora

ge C

ost

Sto

rage

(8,1

89,8

80)

6

Tot

al P

rodu

ctio

n(9

,455

,601

)7 8

T

rans

mis

sion

9

Min

imum

Sys

tem

- T

hrou

ghpu

t Pie

ceM

CF

Thr

ough

put

(13,

202,

817)

10

Dem

and

Rel

ated

Sys

tem

Wei

ghte

d P

eak

Dem

and

(15,

636,

661)

11

Tot

al T

rans

mis

sion

(28,

839,

478)

12 13

Dis

tribu

tion

1430

2/30

3W

eigh

ted

Pea

k D

eman

d(3

08,9

81)

1537

4W

eigh

ted

Pea

k D

eman

d(3

4,89

5)16

375

Wei

ghte

d P

eak

Dem

and

(240

,075

)17

376

(Dem

and)

Wei

ghte

d P

eak

Dem

and

(35,

478,

047)

1837

6 (F

ixed

Cos

t)C

usto

mer

(41,

888,

011)

1937

7M

CF

Thr

ough

put

020

378

Wei

ghte

d P

eak

Dem

and

(3,6

03,2

40)

2137

9W

eigh

ted

Pea

k D

eman

d3,

374

2238

0S

ervi

ces

(44,

651,

434)

2338

1M

eter

s(1

7,76

1,01

5)24

382

Met

ers

025

383

Cus

tom

er(6

,447

,819

)26

385

Acct

385

Dem

and

(372

,979

)27

T

otal

Dis

tribu

tion

(150

,783

,120

)28 29

C

usto

mer

Cus

tom

er0

30 31T

otal

Dep

reci

atio

n R

eser

ve -

Stra

ight

Lin

e:(1

89,0

78,1

99)

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)(O

)

Cus

tom

er C

hoic

e -

Res

iden

tial

Cus

tom

er C

hoic

e -

Sm

all G

SC

usto

mer

Cho

ice

- La

rge

GS

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IC

usto

mer

Cho

ice

- M

ulti-

Fam

ily II

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

III

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IVAg

g T

rans

port

- R

esid

entia

lAg

g T

rans

port

- S

mal

l GS

Agg

Tra

nspo

rt -

Larg

e G

SS

peci

al C

ontra

ct

00

00

00

00

00

0(1

13,6

46)

(104

,311

)0

(142

)(5

27)

0(2

,366

)(2

91)

(70,

559)

(835

)(1

0)(8

00,6

83)

(696

,172

)0

(1,0

47)

(3,5

49)

0(1

5,32

8)(2

,172

)(5

45,6

96)

(10,

544)

(307

)(9

14,3

28)

(800

,483

)0

(1,1

89)

(4,0

76)

0(1

7,69

4)(2

,463

)(6

16,2

55)

(11,

379)

(316

)

(1,0

50,5

02)

(904

,926

)0

(1,3

13)

(4,5

73)

0(2

0,52

5)(2

,686

)(6

12,1

18)

(12,

217)

(143

)(1

,403

,972

)(1

,288

,656

)0

(1,7

55)

(6,5

12)

0(2

9,22

9)(3

,590

)(8

71,6

84)

(10,

318)

(121

)(2

,454

,474

)(2

,193

,582

)0

(3,0

68)

(11,

085)

0(4

9,75

3)(6

,276

)(1

,483

,803

)(2

2,53

6)(2

65)

(27,

743)

(25,

464)

0(3

5)(1

29)

0(5

78)

(71)

(17,

224)

(204

)(2

)(3

,133

)(2

,876

)0

(4)

(15)

0(6

5)(8

)(1

,945

)(2

3)(0

)(2

1,55

6)(1

9,78

5)0

(27)

(100

)0

(449

)(5

5)(1

3,38

3)(1

58)

(2)

(3,1

85,4

74)

(2,9

23,8

33)

0(3

,981

)(1

4,77

6)0

(66,

317)

(8,1

46)

(1,9

77,7

66)

(23,

411)

(275

)(6

,885

,255

)(1

,265

,792

)0

(9,8

30)

(13,

359)

0(2

,773

)(8

,570

)(1

25,5

21)

(756

)(2

52)

00

00

00

00

00

0(3

23,5

25)

(296

,952

)0

(404

)(1

,501

)0

(6,7

35)

(827

)(2

00,8

67)

(2,3

78)

(28)

303

278

00

10

61

188

20

(7,3

71,2

31)

(1,2

78,6

44)

0(1

0,52

4)(1

3,49

4)0

(2,8

01)

(9,1

75)

(126

,795

)(7

64)

(255

)(1

,603

,917

)(2

,399

,558

)0

(1,1

40)

(6,6

67)

0(4

,211

)(2

,112

)(1

75,8

22)

(1,2

04)

(433

)0

00

00

00

00

00

(1,0

59,8

47)

(194

,843

)0

(1,5

13)

(2,0

56)

0(4

27)

(1,3

19)

(19,

321)

(116

)(3

9)0

00

00

00

00

(1,1

06)

(13)

(20,

481,

377)

(8,4

07,4

70)

0(2

7,45

7)(5

2,09

4)0

(84,

348)

(30,

282)

(2,6

58,4

58)

(30,

118)

(1,2

99)

00

00

00

00

00

0

(23,

850,

180)

(11,

401,

535)

0(3

1,71

4)(6

7,25

6)0

(151

,795

)(3

9,02

1)(4

,758

,516

)(6

4,03

4)(1

,880

)

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

RAT

E B

ASE

CO

MP

ON

EN

T -

CO

NS

TR

UC

TIO

N W

OR

K IN

PR

OG

RE

SS

(A)

(B)

(C)

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

Res

iden

tial

Mul

ti-Fa

mily

- C

lass

IM

ulti-

Fam

ily -

Cla

ss II

Mul

ti-Fa

mily

- C

lass

III

Mul

ti-Fa

mily

- C

lass

IV

Sm

all G

ener

al

Ser

vice

Larg

e G

ener

al

Ser

vice

Tra

nspo

rt - T

R-1

Tra

nspo

rt - T

R-2

Tra

nspo

rt - T

R-3

1C

ON

ST

RU

CT

ION

WO

RK

IN P

RO

GR

ES

S2

P

rodu

ctio

n:3

P

urch

ased

Gas

Cos

tS

ales

00

00

00

00

00

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d0

00

00

00

00

00

5

Sto

rage

Cos

tS

tora

ge0

00

00

00

00

00

6

Tot

al P

rodu

ctio

n0

00

00

00

00

00

7 8

Tra

nsm

issi

on9

M

inim

um S

yste

m -

Thr

ough

put P

iece

MC

F T

hrou

ghpu

t0

00

00

00

00

00

10

Dem

and

Rel

ated

Sys

tem

Wei

ghte

d P

eak

Dem

and

00

00

00

00

00

011

T

otal

Tra

nsm

issi

on0

00

00

00

00

00

12 13

Dis

tribu

tion

1430

2/30

3W

eigh

ted

Pea

k D

eman

d0

00

00

00

00

00

1537

4W

eigh

ted

Pea

k D

eman

d0

00

00

00

00

00

1637

5W

eigh

ted

Pea

k D

eman

d0

00

00

00

00

00

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d0

00

00

00

00

00

1837

6 (F

ixed

Cos

t)C

usto

mer

00

00

00

00

00

019

377

MC

F T

hrou

ghpu

t0

00

00

00

00

00

2037

8W

eigh

ted

Pea

k D

eman

d0

00

00

00

00

00

2137

9W

eigh

ted

Pea

k D

eman

d0

00

00

00

00

00

2238

0S

ervi

ces

00

00

00

00

00

023

381

Met

ers

00

00

00

00

00

024

382

Met

ers

00

00

00

00

00

025

383

Cus

tom

er0

00

00

00

00

00

2638

5Ac

ct 3

85 D

eman

d0

00

00

00

00

00

27

Tot

al D

istri

butio

n0

00

00

00

00

00

28 29

Cus

tom

erC

usto

mer

00

00

00

00

00

030 31

Tot

al C

onst

ruct

ion

Wor

k in

Pro

gres

s0

00

00

00

00

00

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

ALLO

CAT

ION

OF

RAT

E B

ASE

CO

MP

ON

EN

T -

CO

NS

TR

UC

TIO

N W

OR

K IN

PR

OG

RE

SS

(A)

(B)

(C)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

1C

ON

ST

RU

CT

ION

WO

RK

IN P

RO

GR

ES

S2

P

rodu

ctio

n:3

P

urch

ased

Gas

Cos

tS

ales

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d0

5

Sto

rage

Cos

tS

tora

ge0

6

Tot

al P

rodu

ctio

n0

7 8

Tra

nsm

issi

on9

M

inim

um S

yste

m -

Thr

ough

put P

iece

MC

F T

hrou

ghpu

t0

10

Dem

and

Rel

ated

Sys

tem

Wei

ghte

d P

eak

Dem

and

011

T

otal

Tra

nsm

issi

on0

12 13

Dis

tribu

tion

1430

2/30

3W

eigh

ted

Pea

k D

eman

d0

1537

4W

eigh

ted

Pea

k D

eman

d0

1637

5W

eigh

ted

Pea

k D

eman

d0

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d0

1837

6 (F

ixed

Cos

t)C

usto

mer

019

377

MC

F T

hrou

ghpu

t0

2037

8W

eigh

ted

Pea

k D

eman

d0

2137

9W

eigh

ted

Pea

k D

eman

d0

2238

0S

ervi

ces

023

381

Met

ers

024

382

Met

ers

025

383

Cus

tom

er0

2638

5Ac

ct 3

85 D

eman

d0

27

Tot

al D

istri

butio

n0

28 29

Cus

tom

erC

usto

mer

030 31

Tot

al C

onst

ruct

ion

Wor

k in

Pro

gres

s0

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)(O

)

Cus

tom

er C

hoic

e -

Res

iden

tial

Cus

tom

er C

hoic

e -

Sm

all G

SC

usto

mer

Cho

ice

- La

rge

GS

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IC

usto

mer

Cho

ice

- M

ulti-

Fam

ily II

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

III

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IVAg

g T

rans

port

- R

esid

entia

lAg

g T

rans

port

- S

mal

l GS

Agg

Tra

nspo

rt -

Larg

e G

SS

peci

al C

ontra

ct

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

0

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

0

00

00

00

00

00

0

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

OT

HE

R R

ATE

BAS

E C

OM

PO

NE

NT

S(A

)(B

)(C

)(D

)(E

)(F

)(G

)(H

)(I)

(J)

(K)

(L)

(N)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

Res

iden

tial

Mul

ti-Fa

mily

- C

lass

IM

ulti-

Fam

ily -

Cla

ss II

Mul

ti-Fa

mily

- C

lass

III

Mul

ti-Fa

mily

- C

lass

IV

Sm

all G

ener

al

Ser

vice

Larg

e G

ener

al

Ser

vice

Tra

nspo

rt - T

R-1

Tra

nspo

rt - T

R-2

Tra

nspo

rt - T

R-3

1 2G

as S

tore

d U

nder

grou

nd:

Sto

rage

14,9

76,5

156,

852,

380

12,5

1765

,352

18,1

2927

,626

1,94

0,74

018

7,61

950

4,69

187

3,06

269

9,01

63 4

Fuel

Sto

ck0

00

00

00

00

00

5 6W

orki

ng C

apita

l Allo

wan

ce7

Ene

rgy

Rel

ated

MC

F T

hrou

ghpu

t2,

746,

387

1,00

6,60

71,

938

10,1

652,

872

4,18

228

5,39

428

,001

166,

691

355,

446

342,

378

8

P

rodu

ctio

n D

eman

d R

elat

edW

eigh

ted

Pea

k D

eman

d23

9,31

687

,714

169

886

250

364

24,8

692,

440

14,5

2530

,973

29,8

349

Tra

nsm

issi

on R

elat

edW

eigh

ted

Pea

k D

eman

d4,

599,

387

1,90

2,31

63,

663

20,4

695,

784

8,42

057

4,68

533

,440

234,

791

424,

486

327,

767

10

D

istri

butio

n R

elat

edW

eigh

ted

Pea

k D

eman

d23

,373

,980

9,72

8,50

616

,622

86,2

4123

,314

37,7

932,

751,

832

261,

270

1,19

3,20

52,

049,

359

1,66

5,70

411

Sto

rage

Rel

ated

Wei

ghte

d P

eak

Dem

and

1,63

2,03

274

6,72

31,

364

7,12

21,

976

3,01

121

1,48

820

,445

54,9

9895

,140

76,1

7412

Cus

tom

er R

elat

edC

usto

mer

00

00

00

00

00

013

S

ub-T

otal

32,5

91,1

0213

,471

,866

23,7

5612

4,88

334

,196

53,7

703,

848,

267

345,

596

1,66

4,21

02,

955,

404

2,44

1,85

614 15

Mat

eria

ls &

Sup

plie

s:16

D

istri

butio

n D

eman

dW

eigh

ted

Pea

k D

eman

d15

3,79

463

,610

122

684

193

282

19,2

161,

118

7,85

114

,194

10,9

6017

D

istri

butio

n Fi

xed

Cos

tC

usto

mer

358,

425

269,

764

269

447

3623

16,3

8436

242

8415

18

Sub

-Tot

al51

2,21

933

3,37

439

11,

131

229

305

35,6

001,

154

8,09

314

,278

10,9

7519 20

Oth

er -

Def

erre

d T

axes

(M&

S /

CW

IP)

21

Dis

tribu

tion

Dem

and

Wei

ghte

d P

eak

Dem

and

00

00

00

00

00

022

D

istri

butio

n Fi

xed

Cos

tC

usto

mer

00

00

00

00

00

023

S

ub-T

otal

00

00

00

00

00

024 25

Pre

paym

ents

:26

Ene

rgy

Rel

ated

MC

F T

hrou

ghpu

t77

828

51

31

181

847

101

9727

Pro

duct

ion

Dem

and

Rel

ated

Wei

ghte

d P

eak

Dem

and

38,4

6515

,909

3117

148

704,

806

280

1,96

43,

550

2,74

128

Tra

nsm

issi

on R

elat

edW

eigh

ted

Pea

k D

eman

d13

,251

5,48

111

5917

241,

656

9667

61,

223

944

29

D

istri

butio

n R

elat

edW

eigh

ted

Pea

k D

eman

d45

9,59

419

0,08

936

62,

045

578

841

57,4

253,

342

23,4

6242

,417

32,7

5230

Sto

rage

Rel

ated

Sto

rage

15,6

007,

138

1368

1929

2,02

219

552

690

972

831

Cus

tom

er R

elat

edC

usto

mer

00

00

00

00

00

032

S

ub-T

otal

527,

688

218,

901

421

2,34

666

296

665

,989

3,92

126

,675

48,2

0037

,263

33 34C

ash

& B

ank

Bal

ance

s:35

Ene

rgy

Rel

ated

MC

F T

hrou

ghpu

t16

962

01

00

182

1022

2136

Pro

duct

ion

Dem

and

Rel

ated

Wei

ghte

d P

eak

Dem

and

187,

795

77,6

7215

083

623

634

423

,465

1,36

59,

587

17,3

3213

,383

37

T

rans

mis

sion

Rel

ated

Wei

ghte

d P

eak

Dem

and

282

117

01

01

352

1426

2038

Dis

tribu

tion

Rel

ated

Wei

ghte

d P

eak

Dem

and

1,43

459

31

62

317

910

7313

210

239

Sto

rage

Rel

ated

Sto

rage

100

460

00

013

13

65

40

C

usto

mer

Rel

ated

Cus

tom

er0

00

00

00

00

00

41

Sub

-Tot

al18

9,78

078

,489

152

845

238

348

23,7

101,

380

9,68

817

,518

13,5

3142 43

Pro

perty

, Pay

roll

& In

com

e T

axes

Acc

rued

:44

Ene

rgy

Rel

ated

MC

F T

hrou

ghpu

t13

,945

5,11

110

5215

211,

449

142

846

1,80

51,

738

45

P

rodu

ctio

n D

eman

d R

elat

edW

eigh

ted

Pea

k D

eman

d(1

9,66

7)(8

,134

)(1

6)(8

8)(2

5)(3

6)(2

,457

)(1

43)

(1,0

04)

(1,8

15)

(1,4

02)

46

T

rans

mis

sion

Rel

ated

Wei

ghte

d P

eak

Dem

and

(407

,820

)(1

68,6

75)

(325

)(1

,815

)(5

13)

(747

)(5

0,95

6)(2

,965

)(2

0,81

9)(3

7,63

9)(2

9,06

3)47

Dis

tribu

tion

Rel

ated

Wei

ghte

d P

eak

Dem

and

(2,1

21,0

64)

(877

,276

)(1

,689

)(9

,439

)(2

,667

)(3

,883

)(2

65,0

23)

(15,

421)

(108

,277

)(1

95,7

57)

(151

,154

)48

Sto

rage

Rel

ated

Sto

rage

(128

,916

)(5

8,98

4)(1

08)

(563

)(1

56)

(238

)(1

6,70

6)(1

,615

)(4

,344

)(7

,515

)(6

,017

)49

Cus

tom

er R

elat

edC

usto

mer

00

00

00

00

00

050

S

ub-T

otal

(2,6

63,5

22)

(1,1

07,9

59)

(2,1

28)

(11,

853)

(3,3

47)

(4,8

83)

(333

,692

)(2

0,00

2)(1

33,5

98)

(240

,922

)(1

85,8

97)

51 52T

OT

AL O

TH

ER

RAT

E B

ASE

CO

MP

ON

EN

TS

46,1

33,7

8219

,847

,052

35,1

0918

2,70

450

,108

78,1

315,

580,

614

519,

669

2,07

9,75

93,

667,

540

3,01

6,74

3

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nP

roje

cted

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyP

roje

cted

Tes

t Yea

r End

ing

Dec

embe

r 31,

201

4

OT

HE

R R

ATE

BAS

E C

OM

PO

NE

NT

S(A

)(B

)(C

)

LIN

E

NO

.D

ES

CR

IPT

ION

ALLO

CAT

ION

FAC

TO

RC

OR

PO

RAT

E

TO

TAL

1 2G

as S

tore

d U

nder

grou

nd:

Sto

rage

14,9

76,5

153 4

Fuel

Sto

ck0

5 6W

orki

ng C

apita

l Allo

wan

ce7

Ene

rgy

Rel

ated

MC

F T

hrou

ghpu

t2,

746,

387

8

P

rodu

ctio

n D

eman

d R

elat

edW

eigh

ted

Pea

k D

eman

d23

9,31

69

Tra

nsm

issi

on R

elat

edW

eigh

ted

Pea

k D

eman

d4,

599,

387

10

D

istri

butio

n R

elat

edW

eigh

ted

Pea

k D

eman

d23

,373

,980

11

S

tora

ge R

elat

edW

eigh

ted

Pea

k D

eman

d1,

632,

032

12

C

usto

mer

Rel

ated

Cus

tom

er0

13

Sub

-Tot

al32

,591

,102

14 15M

ater

ials

& S

uppl

ies:

16

Dis

tribu

tion

Dem

and

Wei

ghte

d P

eak

Dem

and

153,

794

17

Dis

tribu

tion

Fixe

d C

ost

Cus

tom

er35

8,42

518

S

ub-T

otal

512,

219

19 20O

ther

- D

efer

red

Tax

es (M

&S

/ C

WIP

)21

D

istri

butio

n D

eman

dW

eigh

ted

Pea

k D

eman

d0

22

Dis

tribu

tion

Fixe

d C

ost

Cus

tom

er0

23

Sub

-Tot

al0

24 25P

repa

ymen

ts:

26

E

nerg

y R

elat

edM

CF

Thr

ough

put

778

27

P

rodu

ctio

n D

eman

d R

elat

edW

eigh

ted

Pea

k D

eman

d38

,465

28

T

rans

mis

sion

Rel

ated

Wei

ghte

d P

eak

Dem

and

13,2

5129

Dis

tribu

tion

Rel

ated

Wei

ghte

d P

eak

Dem

and

459,

594

30

S

tora

ge R

elat

edS

tora

ge15

,600

31

C

usto

mer

Rel

ated

Cus

tom

er0

32

Sub

-Tot

al52

7,68

833 34

Cas

h &

Ban

k B

alan

ces:

35

E

nerg

y R

elat

edM

CF

Thr

ough

put

169

36

P

rodu

ctio

n D

eman

d R

elat

edW

eigh

ted

Pea

k D

eman

d18

7,79

537

Tra

nsm

issi

on R

elat

edW

eigh

ted

Pea

k D

eman

d28

238

Dis

tribu

tion

Rel

ated

Wei

ghte

d P

eak

Dem

and

1,43

439

Sto

rage

Rel

ated

Sto

rage

100

40

C

usto

mer

Rel

ated

Cus

tom

er0

41

Sub

-Tot

al18

9,78

042 43

Pro

perty

, Pay

roll

& In

com

e T

axes

Acc

rued

:44

Ene

rgy

Rel

ated

MC

F T

hrou

ghpu

t13

,945

45

P

rodu

ctio

n D

eman

d R

elat

edW

eigh

ted

Pea

k D

eman

d(1

9,66

7)46

Tra

nsm

issi

on R

elat

edW

eigh

ted

Pea

k D

eman

d(4

07,8

20)

47

D

istri

butio

n R

elat

edW

eigh

ted

Pea

k D

eman

d(2

,121

,064

)48

Sto

rage

Rel

ated

Sto

rage

(128

,916

)49

Cus

tom

er R

elat

edC

usto

mer

050

S

ub-T

otal

(2,6

63,5

22)

51 52T

OT

AL O

TH

ER

RAT

E B

ASE

CO

MP

ON

EN

TS

46,1

33,7

82

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)(O

)

Cus

tom

er C

hoic

e -

Res

iden

tial

Cus

tom

er C

hoic

e -

Sm

all G

SC

usto

mer

Cho

ice

- La

rge

GS

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IC

usto

mer

Cho

ice

- M

ulti-

Fam

ily II

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

III

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IVAg

g T

rans

port

- R

esid

entia

lAg

g T

rans

port

- S

mal

l GS

Agg

Tra

nspo

rt -

Larg

e G

SS

peci

al C

ontra

ct

1,46

4,17

81,

273,

063

01,

914

6,49

00

28,0

303,

972

997,

893

19,2

8256

1

00

00

00

00

00

0

218,

520

188,

238

027

395

10

4,27

055

912

7,33

02,

541

3019

,042

16,4

030

2483

037

249

11,0

9522

13

412,

966

379,

047

051

61,

916

08,

597

1,05

625

6,39

83,

035

362,

038,

951

1,79

3,18

90

2,81

19,

237

038

,035

5,92

41,

639,

840

30,7

461,

403

159,

555

138,

729

020

970

70

3,05

443

310

8,74

32,

101

610

00

00

00

00

00

2,84

9,03

42,

515,

606

03,

832

12,8

950

54,3

288,

021

2,14

3,40

638

,644

1,53

3

13,8

0912

,675

017

640

287

358,

573

101

158

,915

10,8

310

8411

40

2473

1,07

46

272

,724

23,5

060

101

178

031

110

89,

647

107

3

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

00

0

6253

00

00

10

361

03,

454

3,17

00

416

072

92,

144

250

1,19

01,

092

01

60

253

739

90

41,2

6637

,876

052

191

085

910

625

,621

303

41,

525

1,32

60

27

029

41,

039

201

00

00

00

00

00

047

,496

43,5

180

5922

00

986

122

29,5

7935

84

1312

00

00

00

80

016

,862

15,4

770

2178

035

143

10,4

6912

41

2523

00

00

10

160

012

911

80

01

03

080

10

109

00

00

00

70

00

00

00

00

00

00

17,0

3915

,639

021

790

355

4310

,579

125

1

1,11

095

60

15

022

364

713

0(1

,766

)(1

,621

)0

(2)

(8)

0(3

7)(5

)(1

,096

)(1

3)0

(36,

617)

(33,

609)

0(4

6)(1

70)

0(7

62)

(94)

(22,

734)

(269

)(3

)(1

90,4

44)

(174

,802

)0

(238

)(8

83)

0(3

,965

)(4

87)

(118

,241

)(1

,400

)(1

6)(1

2,60

3)(1

0,95

8)0

(16)

(56)

0(2

41)

(34)

(8,5

90)

(166

)(5

)0

00

00

00

00

00

(240

,321

)(2

20,0

35)

0(3

01)

(1,1

12)

0(4

,983

)(6

17)

(150

,014

)(1

,835

)(2

4)

4,21

0,15

13,

651,

297

05,

626

18,7

490

79,0

2711

,649

3,04

1,08

956

,682

2,07

8

May

not

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Michigan Public Service CommissionMichigan Gas Utilities CorporationProjected Cost of Service Allocation StudyProjected Test Year Ending December 31, 2014Revenue Requirement and Rate Base by Individual Rate Schedule

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: RESIDENTIAL GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 53,882,128 53,882,128 5 Gas Supply Acquisition Cost 382,964 382,964 6 Production Demand 325,271 325,271 7 Storage Cost 304,194 304,194 8 Total - Production 53,882,128 382,964 325,271 304,194 - - - - 54,894,557 910 Transmission: 129,326 12,275 141,601 11 Distribution: 913,738 5,183,784 6,097,522 12 Customer Accounts and Services: - 13 Allocable 8,080,330 8,080,330 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 212,012 180,072 119,926 822,500 - 7,470,906 - 8,805,416 17 Total Operation & Maintenance Expense: 53,882,128 594,976 505,343 424,119 1,865,564 5,196,059 15,551,236 - 78,019,426 1819 Depreciation & Amort Expense: - - 44,815 173,713 1,087,067 4,756,777 - - 6,062,371 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 606 936 563 1,890 15,949 9,264 - 29,209 23 Retirement Benefits - FED 7,242 11,178 6,729 22,568 190,473 110,631 - 348,821 24 IBS Payroll Tax 4,310 6,653 4,005 13,432 113,367 65,846 - 207,614 25 Michigan SBT & Real Estate/Property - - 10,043 186,710 482,753 1,187,894 - - 1,867,400 26 Misc - Unauthorized Ins. Tax & Franchise - - 50 920 2,379 5,855 - - 9,204 27 Total Taxes Other Than Income Taxes: - 12,158 28,859 198,928 523,021 1,513,540 185,741 - 2,462,247 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 8,369 155,579 402,261 989,832 - - 1,556,040 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 53,882,128 607,134 587,386 952,339 3,877,914 12,456,207 15,736,977 - 88,100,085 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (1,412) (26,246) (67,862) (166,985) - - (262,505) 40 Acct 488, Acct 495: Miscellaneous (225,791) (225,791) 41 Acct 495: Customer Penalities & Gas True-up (244,288) (244,288) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (244,288) - (1,412) (26,246) (67,862) (166,985) (225,791) - (732,584) 4445 Actual Return (Net Operating Income) - - 2,481 46,120 119,246 293,424 - - 461,271 4647 Return Income Deficiency - - 37,739 701,599 1,814,037 4,463,744 - - 7,017,119 4849 Additional Income Taxes on Deficiency: - - 9,328 173,411 448,366 1,103,281 - - 1,734,385 5051 REVENUE REQUIREMENTS: 53,637,841 607,134 635,522 1,847,222 6,191,701 18,149,671 15,511,185 - 96,580,276 5253545556 RATE BASE:57 Utility Plant in Service - - 978,347 7,875,091 41,201,815 158,581,675 - - 208,636,928 58 Accumulated Depreciation - S/L - - (523,505) (3,747,212) (22,871,581) (84,571,075) - - (111,713,373) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 454,842 4,127,880 18,330,234 74,010,600 - - 96,923,556 6162 Gas Stored Underground: - - - 6,852,380 - - - - 6,852,380 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 87,714 746,723 12,637,429 - - - 13,471,866 65 Materials & Supplies: - - - - 63,610 269,764 - - 333,374 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 15,909 7,138 195,855 - - - 218,901 68 Cash & Bank Balances - - 77,672 46 772 - - - 78,489 69 Property, Payroll & Income Taxes Accrued: - - (8,134) (58,984) (1,040,840) - - (1,107,959) 70 TOTAL RATE BASE - - 628,003 11,675,181 30,187,060 74,280,364 - - 116,770,608 71 % of Rate Base 0.0000% 0.0000% 0.5378% 9.9984% 25.8516% 63.6122% 0.0000% 0.0000% 100.0000%

COMMODITY DEMAND CUSTOMER




Page 1 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY I GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 103,746 103,746 5 Gas Supply Acquisition Cost 737 737 6 Production Demand 626 626 7 Storage Cost 556 556 8 Total - Production 103,746 737 626 556 - - - - 105,665 910 Transmission: 249 24 273 11 Distribution: 1,759 4,762 6,522 12 Customer Accounts and Services: - 13 Allocable 8,369 8,369 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 408 347 219 1,584 - 7,738 - 10,296 17 Total Operation & Maintenance Expense: 103,746 1,146 973 775 3,592 4,786 16,107 - 131,125 1819 Depreciation & Amort Expense: - - 86 317 2,093 4,694 - - 7,191 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 1 1 3 24 14 - 44 23 Retirement Benefits - FED 11 17 10 34 285 166 - 523 24 IBS Payroll Tax 6 10 6 20 170 99 - 311 25 Michigan SBT & Real Estate/Property - - 19 341 896 1,174 - - 2,430 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 2 4 6 - - 12 27 Total Taxes Other Than Income Taxes: - 18 48 360 957 1,659 278 - 3,320 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 16 284 746 978 - - 2,025 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 103,746 1,164 1,123 1,736 7,388 12,117 16,386 - 143,660 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (3) (45) (118) (155) - - (320) 40 Acct 488, Acct 495: Miscellaneous (225) (225) 41 Acct 495: Customer Penalities & Gas True-up (470) (470) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (470) - (3) (45) (118) (155) (225) - (1,016) 4445 Actual Return (Net Operating Income) - - 20 354 931 1,220 - - 2,525 4647 Return Income Deficiency - - 57 1,011 2,656 3,481 - - 7,206 4849 Additional Income Taxes on Deficiency: - - 18 317 832 1,090 - - 2,257 5051 REVENUE REQUIREMENTS: 103,276 1,164 1,216 3,374 11,690 17,754 16,161 - 154,633 5253545556 RATE BASE:57 Utility Plant in Service - - 1,884 14,386 79,331 158,522 - - 254,122 58 Accumulated Depreciation - S/L - - (1,008) (6,845) (44,038) (85,387) - - (137,277) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 876 7,540 35,294 73,135 - - 116,845 6162 Gas Stored Underground: - - - 12,517 - - - - 12,517 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 169 1,364 22,223 - - - 23,756 65 Materials & Supplies: - - - - 122 269 - - 391 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 31 13 377 - - - 421 68 Cash & Bank Balances - - 150 0 1 - - - 152 69 Property, Payroll & Income Taxes Accrued: - - (16) (108) (2,004) - - (2,128) 70 TOTAL RATE BASE - - 1,210 21,327 56,013 73,404 - - 151,953 71 % of Rate Base 0.0000% 0.0000% 0.7961% 14.0352% 36.8618% 48.3069% 0.0000% 0.0000% 100.0000%





Page 2 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY II GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 544,109 544,109 5 Gas Supply Acquisition Cost 3,867 3,867 6 Production Demand 3,500 3,500 7 Storage Cost 2,901 2,901 8 Total - Production 544,109 3,867 3,500 2,901 - - - - 554,378 910 Transmission: 1,392 124 1,515 11 Distribution: 9,832 12,170 22,002 12 Customer Accounts and Services: - 13 Allocable 20,016 20,016 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 2,141 1,938 1,144 8,850 - 18,506 - 32,578 17 Total Operation & Maintenance Expense: 544,109 6,008 5,437 4,045 20,073 12,294 38,522 - 630,489 1819 Depreciation & Amort Expense: - - 482 1,657 11,697 9,755 - - 23,591 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 4 6 4 12 105 61 - 192 23 Retirement Benefits - FED 48 74 44 148 1,253 728 - 2,294 24 IBS Payroll Tax 28 44 26 88 746 433 - 1,365 25 Michigan SBT & Real Estate/Property - - 107 1,781 4,889 3,056 - - 9,833 26 Misc - Unauthorized Ins. Tax & Franchise - - 1 9 24 15 - - 48 27 Total Taxes Other Than Income Taxes: - 80 231 1,864 5,162 5,174 1,222 - 13,733 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 89 1,484 4,074 2,547 - - 8,193 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 544,109 6,088 6,240 9,049 41,005 29,770 39,744 - 676,006 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (18) (298) (819) (512) - - (1,648) 40 Acct 488, Acct 495: Miscellaneous (374) (374) 41 Acct 495: Customer Penalities & Gas True-up (2,467) (2,467) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (2,467) - (18) (298) (819) (512) (374) - (4,489) 4445 Actual Return (Net Operating Income) - - 934 15,525 42,622 26,644 - - 85,724 4647 Return Income Deficiency - - (505) (8,393) (23,044) (14,405) - - (46,348) 4849 Additional Income Taxes on Deficiency: - - 99 1,654 4,541 2,838 - - 9,132 5051 REVENUE REQUIREMENTS: 541,642 6,088 6,751 17,536 64,305 44,335 39,369 - 720,026 5253545556 RATE BASE:57 Utility Plant in Service - - 10,527 75,106 443,323 399,732 - - 928,687 58 Accumulated Depreciation - S/L - - (5,633) (35,738) (246,093) (209,080) - - (496,543) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 4,894 39,368 197,229 190,652 - - 432,144 6162 Gas Stored Underground: - - - 65,352 - - - - 65,352 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 886 7,122 116,875 - - - 124,883 65 Materials & Supplies: - - - - 684 447 - - 1,131 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 171 68 2,107 - - - 2,346 68 Cash & Bank Balances - - 836 0 8 - - - 845 69 Property, Payroll & Income Taxes Accrued: - - (88) (563) (11,203) - - (11,853) 70 TOTAL RATE BASE - - 6,699 111,348 305,701 191,099 - - 614,848 71 % of Rate Base 0.0000% 0.0000% 1.0895% 18.1098% 49.7199% 31.0807% 0.0000% 0.0000% 100.0000%





Page 3 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY III GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 153,745 153,745 5 Gas Supply Acquisition Cost 1,093 1,093 6 Production Demand 989 989 7 Storage Cost 805 805 8 Total - Production 153,745 1,093 989 805 - - - - 156,631 910 Transmission: 393 35 428 11 Distribution: 2,778 2,137 4,915 12 Customer Accounts and Services: - 13 Allocable 3,042 3,042 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 605 547 317 2,501 - 2,813 - 6,783 17 Total Operation & Maintenance Expense: 153,745 1,698 1,536 1,122 5,672 2,172 5,855 - 171,800 1819 Depreciation & Amort Expense: - - 136 460 3,305 1,375 - - 5,276 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 2 1 3 27 16 - 50 23 Retirement Benefits - FED 12 19 11 38 325 189 - 595 24 IBS Payroll Tax 7 11 7 23 193 112 - 354 25 Michigan SBT & Real Estate/Property - - 30 494 1,365 561 - - 2,450 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 2 7 3 - - 12 27 Total Taxes Other Than Income Taxes: - 21 62 516 1,436 1,109 317 - 3,460 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 25 412 1,137 467 - - 2,041 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 153,745 1,718 1,760 2,509 11,550 5,124 6,172 - 182,578 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (5) (79) (219) (90) - - (393) 40 Acct 488, Acct 495: Miscellaneous (31) (31) 41 Acct 495: Customer Penalities & Gas True-up (697) (697) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (697) - (5) (79) (219) (90) (31) - (1,120) 4445 Actual Return (Net Operating Income) - - 285 4,655 12,860 5,286 - - 23,086 4647 Return Income Deficiency - - (164) (2,677) (7,395) (3,040) - - (13,276) 4849 Additional Income Taxes on Deficiency: - - 28 459 1,267 521 - - 2,275 5051 REVENUE REQUIREMENTS: 153,048 1,718 1,905 4,867 18,063 7,801 6,141 - 193,543 5253545556 RATE BASE:57 Utility Plant in Service - - 2,974 20,834 125,266 71,465 - - 220,540 58 Accumulated Depreciation - S/L - - (1,592) (9,914) (69,537) (36,428) - - (117,470) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 1,383 10,921 55,730 35,036 - - 103,070 6162 Gas Stored Underground: - - - 18,129 - - - - 18,129 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 250 1,976 31,970 - - - 34,196 65 Materials & Supplies: - - - - 193 36 - - 229 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 48 19 595 - - - 662 68 Cash & Bank Balances - - 236 0 2 - - - 238 69 Property, Payroll & Income Taxes Accrued: - - (25) (156) (3,166) - - (3,347) 70 TOTAL RATE BASE - - 1,892 30,888 85,325 35,072 - - 153,178 71 % of Rate Base 0.0000% 0.0000% 1.2351% 20.1650% 55.7033% 22.8966% 0.0000% 0.0000% 100.0000%





Page 4 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY IV GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 223,832 223,832 5 Gas Supply Acquisition Cost 1,591 1,591 6 Production Demand 1,440 1,440 7 Storage Cost 1,226 1,226 8 Total - Production 223,832 1,591 1,440 1,226 - - - - 228,089 910 Transmission: 572 51 623 11 Distribution: 4,044 871 4,916 12 Customer Accounts and Services: - 13 Allocable 3,373 3,373 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 881 797 483 3,641 - 3,119 - 8,920 17 Total Operation & Maintenance Expense: 223,832 2,472 2,237 1,710 8,258 922 6,491 - 245,921 1819 Depreciation & Amort Expense: - - 198 700 4,812 939 - - 6,649 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 2 1 5 39 23 - 71 23 Retirement Benefits - FED 18 27 16 55 464 269 - 849 24 IBS Payroll Tax 10 16 10 33 276 160 - 505 25 Michigan SBT & Real Estate/Property - - 44 753 2,048 419 - - 3,264 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 4 10 2 - - 16 27 Total Taxes Other Than Income Taxes: - 30 90 784 2,150 1,200 452 - 4,706 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 37 627 1,707 349 - - 2,720 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 223,832 2,501 2,562 3,821 16,926 3,409 6,944 - 259,996 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (7) (118) (322) (66) - - (514) 40 Acct 488, Acct 495: Miscellaneous (19) (19) 41 Acct 495: Customer Penalities & Gas True-up (1,015) (1,015) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (1,015) - (7) (118) (322) (66) (19) - (1,548) 4445 Actual Return (Net Operating Income) - - 429 7,333 19,951 4,080 - - 31,793 4647 Return Income Deficiency - - (253) (4,318) (11,749) (2,403) - - (18,723) 4849 Additional Income Taxes on Deficiency: - - 41 699 1,902 389 - - 3,031 5051 REVENUE REQUIREMENTS: 222,817 2,501 2,772 7,417 26,709 5,410 6,924 - 274,550 5253545556 RATE BASE:57 Utility Plant in Service - - 4,330 31,750 182,371 56,582 - - 275,033 58 Accumulated Depreciation - S/L - - (2,317) (15,107) (101,236) (30,412) - - (149,073) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 2,013 16,642 81,135 26,170 - - 125,960 6162 Gas Stored Underground: - - - 27,626 - - - - 27,626 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 364 3,011 50,395 - - - 53,770 65 Materials & Supplies: - - - - 282 23 - - 305 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 70 29 867 - - - 966 68 Cash & Bank Balances - - 344 0 3 - - - 348 69 Property, Payroll & Income Taxes Accrued: - - (36) (238) (4,609) - - (4,883) 70 TOTAL RATE BASE - - 2,755 47,070 128,073 26,193 - - 204,091 71 % of Rate Base 0.0000% 0.0000% 1.3500% 23.0632% 62.7530% 12.8338% 0.0000% 0.0000% 100.0000%





Page 5 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: SMALL GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 15,276,696 15,276,696 5 Gas Supply Acquisition Cost 108,578 108,578 6 Production Demand 98,263 98,263 7 Storage Cost 86,154 86,154 8 Total - Production 15,276,696 108,578 98,263 86,154 - - - - 15,569,692 910 Transmission: 39,069 3,480 42,549 11 Distribution: 276,038 692,088 968,125 12 Customer Accounts and Services: - 13 Allocable 685,155 685,155 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 60,110 54,399 33,965 248,475 - 633,480 - 1,030,430 17 Total Operation & Maintenance Expense: 15,276,696 168,688 152,663 120,120 563,582 695,568 1,318,635 - 18,295,952 1819 Depreciation & Amort Expense: - - 13,539 49,199 328,400 431,296 - - 822,433 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 116 179 108 362 3,053 1,773 - 5,591 23 Retirement Benefits - FED 1,386 2,139 1,288 4,319 36,457 21,175 - 66,765 24 IBS Payroll Tax 825 1,273 767 2,571 21,699 12,603 - 39,737 25 Michigan SBT & Real Estate/Property - - 3,008 52,880 142,545 147,160 - - 345,594 26 Misc - Unauthorized Ins. Tax & Franchise - - 15 261 703 725 - - 1,703 27 Total Taxes Other Than Income Taxes: - 2,327 6,615 55,303 150,500 209,094 35,551 - 459,390 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2,506 44,063 118,778 122,624 - - 287,971 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 15,276,696 171,015 175,323 268,685 1,161,260 1,458,581 1,354,186 - 19,865,746 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (449) (7,892) (21,274) (21,963) - - (51,578) 40 Acct 488, Acct 495: Miscellaneous (13,713) (13,713) 41 Acct 495: Customer Penalities & Gas True-up (69,261) (69,261) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (69,261) - (449) (7,892) (21,274) (21,963) (13,713) - (134,551) 4445 Actual Return (Net Operating Income) - - 19,282 338,989 913,785 943,371 - - 2,215,427 4647 Return Income Deficiency - - (7,236) (127,219) (342,934) (354,037) - - (831,426) 4849 Additional Income Taxes on Deficiency: - - 2,794 49,114 132,392 136,678 - - 320,977 5051 REVENUE REQUIREMENTS: 15,207,436 171,015 189,713 521,677 1,843,229 2,162,630 1,340,472 - 21,436,173 5253545556 RATE BASE:57 Utility Plant in Service - - 295,556 2,230,394 12,446,959 18,481,855 - - 33,454,764 58 Accumulated Depreciation - S/L - - (158,149) (1,061,290) (6,909,444) (9,296,140) - - (17,425,024) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 137,407 1,169,104 5,537,515 9,185,715 - - 16,029,741 6162 Gas Stored Underground: - - - 1,940,740 - - - - 1,940,740 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 24,869 211,488 3,611,911 - - - 3,848,267 65 Materials & Supplies: - - - - 19,216 16,384 - - 35,600 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 4,806 2,022 59,162 - - - 65,989 68 Cash & Bank Balances - - 23,465 13 232 - - - 23,710 69 Property, Payroll & Income Taxes Accrued: - - (2,457) (16,706) (314,530) - - (333,692) 70 TOTAL RATE BASE - - 188,090 3,306,660 8,913,506 9,202,099 - - 21,610,355 71 % of Rate Base 0.0000% 0.0000% 0.8704% 15.3013% 41.2465% 42.5819% 0.0000% 0.0000% 100.0000%





Page 6 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: LARGE GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 1,498,862 1,498,862 5 Gas Supply Acquisition Cost 10,653 10,653 6 Production Demand 5,718 5,718 7 Storage Cost 8,329 8,329 8 Total - Production 1,498,862 10,653 5,718 8,329 - - - - 1,523,562 910 Transmission: 2,273 341 2,615 11 Distribution: 17,159 1,532 18,691 12 Customer Accounts and Services: - 13 Allocable 17,095 17,095 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 5,898 3,165 3,284 15,445 - 15,806 - 43,598 17 Total Operation & Maintenance Expense: 1,498,862 16,551 8,883 11,612 34,877 1,874 32,901 - 1,605,560 1819 Depreciation & Amort Expense: - - 788 4,756 19,731 3,589 - - 28,864 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 6 9 6 18 156 90 - 285 23 Retirement Benefits - FED 71 109 66 220 1,860 1,080 - 3,407 24 IBS Payroll Tax 42 65 39 131 1,107 643 - 2,028 25 Michigan SBT & Real Estate/Property - - 191 5,112 10,227 1,980 - - 17,510 26 Misc - Unauthorized Ins. Tax & Franchise - - 1 25 50 10 - - 86 27 Total Taxes Other Than Income Taxes: - 119 375 5,248 10,647 5,113 1,814 - 23,316 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 159 4,260 8,522 1,650 - - 14,591 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 1,498,862 16,669 10,205 25,876 73,777 12,226 34,715 - 1,672,331 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (32) (868) (1,736) (336) - - (2,972) 40 Acct 488, Acct 495: Miscellaneous (30) (30) 41 Acct 495: Customer Penalities & Gas True-up (6,795) (6,795) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (6,795) - (32) (868) (1,736) (336) (30) - (9,797) 4445 Actual Return (Net Operating Income) - - 2,406 64,425 128,883 24,955 - - 220,669 4647 Return Income Deficiency - - (1,641) (43,953) (87,927) (17,025) - - (150,546) 4849 Additional Income Taxes on Deficiency: - - 177 4,748 9,498 1,839 - - 16,263 5051 REVENUE REQUIREMENTS: 1,492,066 16,669 11,115 50,229 122,495 21,659 34,685 - 1,748,919 5253545556 RATE BASE:57 Utility Plant in Service - - 17,198 215,621 744,688 275,875 - - 1,253,381 58 Accumulated Depreciation - S/L - - (9,202) (102,599) (414,236) (152,088) - - (678,126) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 7,995 113,022 330,452 123,787 - - 575,255 6162 Gas Stored Underground: - - - 187,619 - - - - 187,619 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 2,440 20,445 322,711 - - - 345,596 65 Materials & Supplies: - - - - 1,118 36 - - 1,154 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 280 195 3,446 - - - 3,921 68 Cash & Bank Balances - - 1,365 1 14 - - - 1,380 69 Property, Payroll & Income Taxes Accrued: - - (143) (1,615) (18,244) - - (20,002) 70 TOTAL RATE BASE - - 11,937 319,668 639,496 123,823 - - 1,094,924 71 % of Rate Base 0.0000% 0.0000% 1.0903% 29.1954% 58.4055% 11.3088% 0.0000% 0.0000% 100.0000%





Page 7 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: TRANSPORT - TR1 GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 40,146 40,146 7 Storage Cost 22,404 22,404 8 Total - Production - - 40,146 22,404 - - - - 62,551 910 Transmission: 15,962 2,033 17,995 11 Distribution: 120,475 13,044 133,519 12 Customer Accounts and Services: - 13 Allocable 107,570 107,570 14 Transport Allocable 44,320 44,320 15 Customer Sales: - - 16 Administrative & General: - - 22,225 8,833 108,445 - 99,457 28,815 267,775 17 Total Operation & Maintenance Expense: - - 62,371 31,237 244,882 15,077 207,028 73,135 633,730 1819 Depreciation & Amort Expense: - - 5,531 12,794 138,537 23,440 - - 180,303 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 103 37 126 1,061 616 - 1,944 23 Retirement Benefits - FED 1,226 448 1,502 12,676 7,362 - 23,214 24 IBS Payroll Tax 730 267 894 7,545 4,382 - 13,817 25 Michigan SBT & Real Estate/Property - - 1,299 13,752 61,070 12,507 - - 88,627 26 Misc - Unauthorized Ins. Tax & Franchise - - 6 68 301 62 - - 437 27 Total Taxes Other Than Income Taxes: - - 3,363 14,571 63,892 33,851 12,361 - 128,038 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 1,082 11,459 50,887 10,422 - - 73,850 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 72,348 70,061 498,198 82,790 219,389 73,135 1,015,921 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (273) (2,890) (12,835) (2,629) - - (18,627) 40 Acct 488, Acct 495: Miscellaneous (202) (202) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (273) (2,890) (12,835) (2,629) (202) - (18,829) 4445 Actual Return (Net Operating Income) - - 20,687 219,040 972,741 199,219 - - 1,411,687 4647 Return Income Deficiency - - (15,486) (163,969) (728,175) (149,132) - - (1,056,761) 4849 Additional Income Taxes on Deficiency: - - 1,206 12,772 56,720 11,616 - - 82,314 5051 REVENUE REQUIREMENTS: - - 78,482 135,014 786,649 141,865 219,186 73,135 1,434,332 5253545556 RATE BASE:57 Utility Plant in Service - - 120,751 580,016 5,228,645 1,729,462 - - 7,658,875 58 Accumulated Depreciation - S/L - - (64,613) (275,990) (2,908,459) (947,616) - - (4,196,678) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 56,138 304,027 2,320,186 781,846 - - 3,462,197 6162 Gas Stored Underground: - - - 504,691 - - - - 504,691 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 14,525 54,998 1,594,687 - - - 1,664,210 65 Materials & Supplies: - - - - 7,851 242 - - 8,093 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 1,964 526 24,185 - - - 26,675 68 Cash & Bank Balances - - 9,587 3 98 - - - 9,688 69 Property, Payroll & Income Taxes Accrued: - - (1,004) (4,344) (128,250) - - (133,598) 70 TOTAL RATE BASE - - 81,210 859,900 3,818,757 782,088 - - 5,541,956 71 % of Rate Base 0.0000% 0.0000% 1.4654% 15.5162% 68.9063% 14.1121% 0.0000% 0.0000% 100.0000%





Page 8 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 72,582 72,582 7 Storage Cost 38,757 38,757 8 Total - Production - - 72,582 38,757 - - - - 111,339 910 Transmission: 28,858 4,335 33,193 11 Distribution: 217,810 4,521 222,331 12 Customer Accounts and Services: - 13 Allocable 112,355 112,355 14 Transport Allocable 15,433 15,433 15 Customer Sales: - - 16 Administrative & General: - - 40,182 15,280 196,061 - 103,881 10,034 365,437 17 Total Operation & Maintenance Expense: - - 112,763 54,037 442,729 8,856 216,236 25,467 860,088 1819 Depreciation & Amort Expense: - - 10,000 22,133 250,465 36,841 - - 319,438 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 184 67 226 1,908 1,108 - 3,494 23 Retirement Benefits - FED 2,203 805 2,700 22,785 13,234 - 41,726 24 IBS Payroll Tax 1,311 479 1,607 13,561 7,877 - 24,835 25 Michigan SBT & Real Estate/Property - - 2,423 23,789 109,554 22,334 - - 158,100 26 Misc - Unauthorized Ins. Tax & Franchise - - 12 117 540 110 - - 779 27 Total Taxes Other Than Income Taxes: - - 6,135 25,257 114,627 60,698 22,219 - 228,935 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2,019 19,822 91,288 18,610 - - 131,739 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 130,917 121,250 899,108 125,004 238,455 25,467 1,540,200 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (310) (3,042) (14,008) (2,856) - - (20,215) 40 Acct 488, Acct 495: Miscellaneous (70) (70) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (310) (3,042) (14,008) (2,856) (70) - (20,285) 4445 Actual Return (Net Operating Income) - - 16,773 164,649 758,257 154,580 - - 1,094,258 4647 Return Income Deficiency - - (7,068) (69,382) (319,524) (65,139) - - (461,113) 4849 Additional Income Taxes on Deficiency: - - 2,251 22,094 101,751 20,743 - - 146,839 5051 REVENUE REQUIREMENTS: - - 142,563 235,569 1,425,583 232,332 238,384 25,467 2,299,899 5253545556 RATE BASE:57 Utility Plant in Service - - 218,310 1,003,366 9,453,021 3,155,991 - - 13,830,688 58 Accumulated Depreciation - S/L - - (116,816) (477,432) (5,258,289) (1,759,508) - - (7,612,045) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 101,494 525,933 4,194,732 1,396,483 - - 6,218,642 6162 Gas Stored Underground: - - - 873,062 - - - - 873,062 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 30,973 95,140 2,829,291 - - - 2,955,404 65 Materials & Supplies: - - - - 14,194 84 - - 14,278 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 3,550 909 43,740 - - - 48,200 68 Cash & Bank Balances - - 17,332 6 180 - - - 17,518 69 Property, Payroll & Income Taxes Accrued: - - (1,815) (7,515) (231,591) - - (240,922) 70 TOTAL RATE BASE - - 151,534 1,487,535 6,850,546 1,396,567 - - 9,886,182 71 % of Rate Base 0.0000% 0.0000% 1.5328% 15.0466% 69.2942% 14.1264% 0.0000% 0.0000% 100.0000%





Page 9 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 56,044 56,044 7 Storage Cost 31,031 31,031 8 Total - Production - - 56,044 31,031 - - - - 87,075 910 Transmission: 22,283 4,175 26,458 11 Distribution: 168,182 690 168,871 12 Customer Accounts and Services: - 13 Allocable 71,376 71,376 14 Transport Allocable 2,770 2,770 15 Customer Sales: - - 16 Administrative & General: - - 31,026 12,234 151,389 - 65,993 1,801 262,442 17 Total Operation & Maintenance Expense: - - 87,070 43,265 341,853 4,865 137,368 4,571 618,992 1819 Depreciation & Amort Expense: - - 7,722 17,721 193,396 33,442 - - 252,280 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 142 52 175 1,473 855 - 2,697 23 Retirement Benefits - FED 1,701 621 2,084 17,589 10,216 - 32,211 24 IBS Payroll Tax 1,012 370 1,240 10,469 6,080 - 19,172 25 Michigan SBT & Real Estate/Property - - 1,966 19,046 87,016 20,833 - - 128,861 26 Misc - Unauthorized Ins. Tax & Franchise - - 10 94 429 103 - - 635 27 Total Taxes Other Than Income Taxes: - - 4,831 20,184 90,944 50,466 17,152 - 183,576 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 1,638 15,871 72,508 17,359 - - 107,376 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 101,261 97,040 698,701 106,131 154,520 4,571 1,162,224 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (199) (1,924) (8,789) (2,104) - - (13,015) 40 Acct 488, Acct 495: Miscellaneous (13) (13) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (199) (1,924) (8,789) (2,104) (13) - (13,028) 4445 Actual Return (Net Operating Income) - - 8,145 78,914 360,530 86,316 - - 533,904 4647 Return Income Deficiency - - (272) (2,639) (12,055) (2,886) - - (17,852) 4849 Additional Income Taxes on Deficiency: - - 1,826 17,690 80,818 19,349 - - 119,683 5051 REVENUE REQUIREMENTS: - - 110,761 189,081 1,119,205 206,806 154,507 4,571 1,784,930 5253545556 RATE BASE:57 Utility Plant in Service - - 168,568 803,344 7,299,143 2,956,707 - - 11,227,761 58 Accumulated Depreciation - S/L - - (90,199) (382,256) (4,060,184) (1,654,021) - - (6,186,660) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 78,369 421,088 3,238,959 1,302,686 - - 5,041,102 6162 Gas Stored Underground: - - - 699,016 - - - - 699,016 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 29,834 76,174 2,335,848 - - - 2,441,856 65 Materials & Supplies: - - - - 10,960 15 - - 10,975 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 2,741 728 33,793 - - - 37,263 68 Cash & Bank Balances - - 13,383 5 143 - - - 13,531 69 Property, Payroll & Income Taxes Accrued: - - (1,402) (6,017) (178,478) - - (185,897) 70 TOTAL RATE BASE - - 122,925 1,190,994 5,441,226 1,302,701 - - 8,057,845 71 % of Rate Base 0.0000% 0.0000% 1.5255% 14.7805% 67.5271% 16.1669% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: CUST CHOICE - RESID. GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 70,612 70,612 7 Storage Cost 64,998 64,998 8 Total - Production - - 70,612 64,998 - - - - 135,610 910 Transmission: 28,075 2,665 30,740 11 Distribution: 198,360 1,073,068 1,271,427 12 Customer Accounts and Services: - 13 Allocable 1,765,082 1,765,082 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 39,091 25,625 178,553 - 1,631,958 - 1,875,227 17 Total Operation & Maintenance Expense: - - 109,703 90,623 404,988 1,075,732 3,397,040 - 5,078,086 1819 Depreciation & Amort Expense: - - 9,729 37,118 235,987 1,018,987 - - 1,301,821 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 336 123 411 3,471 2,016 - 6,357 23 Retirement Benefits - FED 4,009 1,464 4,911 41,452 24,076 - 75,913 24 IBS Payroll Tax 2,386 872 2,923 24,672 14,330 - 45,182 25 Michigan SBT & Real Estate/Property - - 2,180 39,895 103,632 249,647 - - 395,355 26 Misc - Unauthorized Ins. Tax & Franchise - - 11 197 511 1,231 - - 1,949 27 Total Taxes Other Than Income Taxes: - - 8,921 42,551 112,388 320,473 40,422 - 524,755 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 1,817 33,243 86,353 208,023 - - 329,436 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 130,169 203,535 839,716 2,623,215 3,437,462 - 7,234,098 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (317) (5,792) (15,045) (36,244) - - (57,398) 40 Acct 488, Acct 495: Miscellaneous (49,312) (49,312) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (317) (5,792) (15,045) (36,244) (49,312) - (106,710) 4445 Actual Return (Net Operating Income) - - 1,628 29,792 77,388 186,426 - - 295,233 4647 Return Income Deficiency - - 7,103 129,976 337,628 813,339 - - 1,288,046 4849 Additional Income Taxes on Deficiency: - - 2,025 37,053 96,250 231,865 - - 367,194 5051 REVENUE REQUIREMENTS: - - 140,609 394,565 1,335,936 3,818,601 3,388,150 - 9,077,861 5253545556 RATE BASE:57 Utility Plant in Service - - 212,385 1,682,705 8,944,336 33,522,573 - - 44,361,999 58 Accumulated Depreciation - S/L - - (113,646) (800,683) (4,965,099) (17,970,752) - - (23,850,180) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 98,740 882,022 3,979,237 15,551,821 - - 20,511,820 6162 Gas Stored Underground: - - - 1,464,178 - - - - 1,464,178 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 19,042 159,555 2,670,437 - - - 2,849,034 65 Materials & Supplies: - - - - 13,809 58,915 - - 72,724 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 3,454 1,525 42,517 - - - 47,496 68 Cash & Bank Balances - - 16,862 10 168 - - - 17,039 69 Property, Payroll & Income Taxes Accrued: - - (1,766) (12,603) (225,952) - - (240,321) 70 TOTAL RATE BASE - - 136,332 2,494,687 6,480,216 15,610,736 - - 24,721,970 71 % of Rate Base 0.0000% 0.0000% 0.5515% 10.0910% 26.2124% 63.1452% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: CUST CHOICE - SMALL GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 64,812 64,812 7 Storage Cost 56,514 56,514 8 Total - Production - - 64,812 56,514 - - - - 121,326 910 Transmission: 25,769 2,295 28,064 11 Distribution: 182,067 445,585 627,653 12 Customer Accounts and Services: - 13 Allocable 453,860 453,860 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 35,880 22,280 163,888 - 419,629 - 641,677 17 Total Operation & Maintenance Expense: - - 100,692 78,795 371,724 447,881 873,489 - 1,872,580 1819 Depreciation & Amort Expense: - - 8,930 32,273 216,604 281,087 - - 538,894 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 195 71 239 2,014 1,170 - 3,688 23 Retirement Benefits - FED 2,326 850 2,850 24,051 13,969 - 44,045 24 IBS Payroll Tax 1,384 506 1,696 14,315 8,314 - 26,215 25 Michigan SBT & Real Estate/Property - - 1,984 34,688 93,670 95,297 - - 225,638 26 Misc - Unauthorized Ins. Tax & Franchise - - 10 171 462 470 - - 1,112 27 Total Taxes Other Than Income Taxes: - - 5,899 36,285 98,916 136,145 23,453 - 300,698 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 1,653 28,904 78,052 79,407 - - 188,016 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 117,174 176,257 765,295 944,521 896,942 - 2,900,188 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (301) (5,268) (14,225) (14,472) - - (34,265) 40 Acct 488, Acct 495: Miscellaneous (9,066) (9,066) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (301) (5,268) (14,225) (14,472) (9,066) - (43,331) 4445 Actual Return (Net Operating Income) - - 13,842 242,012 653,521 664,872 - - 1,574,247 4647 Return Income Deficiency - - (5,897) (103,098) (278,402) (283,237) - - (670,634) 4849 Additional Income Taxes on Deficiency: - - 1,843 32,217 86,998 88,509 - - 209,566 5051 REVENUE REQUIREMENTS: - - 126,660 342,120 1,213,188 1,400,193 887,876 - 3,970,037 5253545556 RATE BASE:57 Utility Plant in Service - - 194,941 1,463,066 8,209,688 11,991,935 - - 21,859,630 58 Accumulated Depreciation - S/L - - (104,311) (696,172) (4,557,288) (6,043,764) - - (11,401,535) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 90,630 766,894 3,652,400 5,948,171 - - 10,458,095 6162 Gas Stored Underground: - - - 1,273,063 - - - - 1,273,063 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 16,403 138,729 2,360,474 - - - 2,515,606 65 Materials & Supplies: - - - - 12,675 10,831 - - 23,506 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 3,170 1,326 39,022 - - - 43,518 68 Cash & Bank Balances - - 15,477 9 153 - - - 15,639 69 Property, Payroll & Income Taxes Accrued: - - (1,621) (10,958) (207,455) - - (220,035) 70 TOTAL RATE BASE - - 124,059 2,169,062 5,857,268 5,959,002 - - 14,109,392 71 % of Rate Base 0.0000% 0.0000% 0.8793% 15.3732% 41.5133% 42.2343% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: CUST CHOICE - LARGE GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand - - 7 Storage Cost - - 8 Total - Production - - - - - - - - - 910 Transmission: - - - 11 Distribution: - - - 12 Customer Accounts and Services: - 13 Allocable - - 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - - - - - - - - 17 Total Operation & Maintenance Expense: - - - - - - - - - 1819 Depreciation & Amort Expense: - - - - - - - - - 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE - - - - - - - 23 Retirement Benefits - FED - - - - - - - 24 IBS Payroll Tax - - - - - - - 25 Michigan SBT & Real Estate/Property - - - - - - - - - 26 Misc - Unauthorized Ins. Tax & Franchise - - - - - - - - - 27 Total Taxes Other Than Income Taxes: - - - - - - - - - 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - - - - - - - - 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - - - - - - - - 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - - - - - - - - 40 Acct 488, Acct 495: Miscellaneous - - 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - - - - - - - - 4445 Actual Return (Net Operating Income) - - - - - - - - - 4647 Return Income Deficiency - - - - - - - - - 4849 Additional Income Taxes on Deficiency: - - - - - - - - - 5051 REVENUE REQUIREMENTS: - - - - - - - - - 5253545556 RATE BASE:57 Utility Plant in Service - - - - - - - - - 58 Accumulated Depreciation - S/L - - - - - - - - - 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - - - - - - - - 6162 Gas Stored Underground: - - - - - - - - - 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - - - - - - - - 65 Materials & Supplies: - - - - - - - - - 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - - - - - - - - 68 Cash & Bank Balances - - - - - - - - - 69 Property, Payroll & Income Taxes Accrued: - - - - - - - - 70 TOTAL RATE BASE - - - - - - - - - 71 % of Rate Base 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000% 0.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: CUST CHOICE - MULTI FAM 1 GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 88 88 7 Storage Cost 85 85 8 Total - Production - - 88 85 - - - - 173 910 Transmission: 35 3 38 11 Distribution: 248 1,394 1,642 12 Customer Accounts and Services: - 13 Allocable 2,440 2,440 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 49 33 223 - 2,256 - 2,562 17 Total Operation & Maintenance Expense: - - 137 118 506 1,398 4,697 - 6,856 1819 Depreciation & Amort Expense: - - 12 49 295 1,405 - - 1,761 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 0 0 1 5 3 - 8 23 Retirement Benefits - FED 5 2 7 55 32 - 101 24 IBS Payroll Tax 3 1 4 33 19 - 60 25 Michigan SBT & Real Estate/Property - - 3 52 134 331 - - 520 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 0 1 2 - - 3 27 Total Taxes Other Than Income Taxes: - - 12 56 145 426 54 - 692 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2 43 111 276 - - 433 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 163 266 1,058 3,504 4,750 - 9,742 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (0) (7) (17) (43) - - (67) 40 Acct 488, Acct 495: Miscellaneous (70) (70) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (0) (7) (17) (43) (70) - (138) 4445 Actual Return (Net Operating Income) - - (5) (90) (230) (571) - - (896) 4647 Return Income Deficiency - - 16 299 766 1,898 - - 2,979 4849 Additional Income Taxes on Deficiency: - - 3 48 124 308 - - 483 5051 REVENUE REQUIREMENTS: - - 176 517 1,700 5,097 4,680 - 12,170 5253545556 RATE BASE:57 Utility Plant in Service - - 265 2,199 11,179 44,959 - - 58,604 58 Accumulated Depreciation - S/L - - (142) (1,047) (6,206) (24,319) - - (31,714) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 123 1,153 4,974 20,640 - - 26,890 6162 Gas Stored Underground: - - - 1,914 - - - - 1,914 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 24 209 3,600 - - - 3,832 65 Materials & Supplies: - - - - 17 84 - - 101 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 4 2 53 - - - 59 68 Cash & Bank Balances - - 21 0 0 - - - 21 69 Property, Payroll & Income Taxes Accrued: - - (2) (16) (283) - - (301) 70 TOTAL RATE BASE - - 170 3,261 8,361 20,724 - - 32,516 71 % of Rate Base 0.0000% 0.0000% 0.5241% 10.0288% 25.7132% 63.7340% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 328 328 7 Storage Cost 288 288 8 Total - Production - - 328 288 - - - - 616 910 Transmission: 130 12 142 11 Distribution: 920 2,467 3,387 12 Customer Accounts and Services: - 13 Allocable 4,225 4,225 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 181 114 828 - 3,907 - 5,030 17 Total Operation & Maintenance Expense: - - 509 402 1,879 2,479 8,132 - 13,400 1819 Depreciation & Amort Expense: - - 45 165 1,095 2,119 - - 3,423 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 0 1 12 7 - 22 23 Retirement Benefits - FED 14 5 17 141 82 - 258 24 IBS Payroll Tax 8 3 10 84 49 - 153 25 Michigan SBT & Real Estate/Property - - 10 177 476 576 - - 1,239 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 1 2 3 - - 6 27 Total Taxes Other Than Income Taxes: - - 33 186 507 815 137 - 1,678 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 8 147 397 480 - - 1,032 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 595 900 3,876 5,893 8,270 - 19,534 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (2) (37) (99) (120) - - (258) 40 Acct 488, Acct 495: Miscellaneous (96) (96) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (2) (37) (99) (120) (96) - (354) 4445 Actual Return (Net Operating Income) - - 115 2,028 5,460 6,603 - - 14,206 4647 Return Income Deficiency - - (75) (1,320) (3,553) (4,297) - - (9,245) 4849 Additional Income Taxes on Deficiency: - - 9 164 442 535 - - 1,151 5051 REVENUE REQUIREMENTS: - - 643 1,735 6,126 8,614 8,174 - 25,292 5253545556 RATE BASE:57 Utility Plant in Service - - 985 7,458 41,488 76,040 - - 125,972 58 Accumulated Depreciation - S/L - - (527) (3,549) (23,030) (40,149) - - (67,256) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 458 3,909 18,458 35,891 - - 58,716 6162 Gas Stored Underground: - - - 6,490 - - - - 6,490 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 83 707 12,105 - - - 12,895 65 Materials & Supplies: - - - - 64 114 - - 178 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 16 7 197 - - - 220 68 Cash & Bank Balances - - 78 0 1 - - - 79 69 Property, Payroll & Income Taxes Accrued: - - (8) (56) (1,049) - - (1,112) 70 TOTAL RATE BASE - - 627 11,058 29,776 36,005 - - 77,465 71 % of Rate Base 0.0000% 0.0000% 0.8094% 14.2743% 38.4375% 46.4788% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)








(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 1,470 1,470 7 Storage Cost 1,244 1,244 8 Total - Production - - 1,470 1,244 - - - - 2,714 910 Transmission: 584 52 637 11 Distribution: 4,130 851 4,980 12 Customer Accounts and Services: - 13 Allocable 3,473 3,473 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 814 491 3,717 - 3,211 - 8,232 17 Total Operation & Maintenance Expense: - - 2,284 1,735 8,431 903 6,683 - 20,036 1819 Depreciation & Amort Expense: - - 203 711 4,913 946 - - 6,772 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 4 1 5 40 23 - 73 23 Retirement Benefits - FED 46 17 56 473 275 - 867 24 IBS Payroll Tax 27 10 33 282 164 - 516 25 Michigan SBT & Real Estate/Property - - 45 764 2,082 421 - - 3,313 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 4 10 2 - - 16 27 Total Taxes Other Than Income Taxes: - - 122 796 2,187 1,218 462 - 4,785 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 37 636 1,735 351 - - 2,760 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 2,646 3,877 17,266 3,418 7,145 - 34,353 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (7) (122) (333) (67) - - (529) 40 Acct 488, Acct 495: Miscellaneous (20) (20) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (7) (122) (333) (67) (20) - (549) 4445 Actual Return (Net Operating Income) - - 471 7,989 21,784 4,408 - - 34,652 4647 Return Income Deficiency - - (290) (4,931) (13,444) (2,721) - - (21,386) 4849 Additional Income Taxes on Deficiency: - - 42 709 1,934 391 - - 3,077 5051 REVENUE REQUIREMENTS: - - 2,861 7,523 27,207 5,430 7,125 - 50,145 5253545556 RATE BASE:57 Utility Plant in Service - - 4,422 32,213 186,207 57,062 - - 279,904 58 Accumulated Depreciation - S/L - - (2,366) (15,328) (103,366) (30,736) - - (151,795) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 2,056 16,885 82,841 26,326 - - 128,108 6162 Gas Stored Underground: - - - 28,030 - - - - 28,030 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 372 3,054 50,902 - - - 54,328 65 Materials & Supplies: - - - - 287 24 - - 311 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 72 29 885 - - - 986 68 Cash & Bank Balances - - 351 0 3 - - - 355 69 Property, Payroll & Income Taxes Accrued: - - (37) (241) (4,705) - - (4,983) 70 TOTAL RATE BASE - - 2,814 47,758 130,214 26,350 - - 207,135 71 % of Rate Base 0.0000% 0.0000% 1.3583% 23.0563% 62.8642% 12.7212% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: AGG TRNSPT - RESID. GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 181 181 7 Storage Cost 176 176 8 Total - Production - - 181 176 - - - - 357 910 Transmission: 72 7 79 11 Distribution: 507 1,349 1,857 12 Customer Accounts and Services: - 13 Allocable 2,408 2,408 14 Transport Allocable 13,454 13,454 15 Customer Sales: - - 16 Administrative & General: - - 100 70 457 - 2,227 8,747 11,600 17 Total Operation & Maintenance Expense: - - 281 246 1,036 1,356 4,635 22,202 29,755 1819 Depreciation & Amort Expense: - - 25 101 603 1,301 - - 2,030 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 0 1 7 4 - 12 23 Retirement Benefits - FED 8 3 10 81 47 - 149 24 IBS Payroll Tax 5 2 6 48 28 - 88 25 Michigan SBT & Real Estate/Property - - 6 108 276 330 - - 720 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 1 1 2 - - 4 27 Total Taxes Other Than Income Taxes: - - 19 114 294 468 79 - 974 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 5 90 230 275 - - 600 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 329 550 2,163 3,400 4,714 22,202 33,358 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (1) (17) (42) (51) - - (110) 40 Acct 488, Acct 495: Miscellaneous (61) (61) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (1) (17) (42) (51) (61) - (172) 4445 Actual Return (Net Operating Income) - - (147) (2,845) (7,265) (8,684) - - (18,940) 4647 Return Income Deficiency - - 169 3,278 8,371 10,006 - - 21,825 4849 Additional Income Taxes on Deficiency: - - 5 101 257 307 - - 669 5051 REVENUE REQUIREMENTS: - - 355 1,068 3,484 4,979 4,652 22,202 36,741 5253545556 RATE BASE:57 Utility Plant in Service - - 543 4,565 22,872 44,444 - - 72,424 58 Accumulated Depreciation - S/L - - (291) (2,172) (12,697) (23,861) - - (39,021) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 252 2,393 10,176 20,583 - - 33,404 6162 Gas Stored Underground: - - - 3,972 - - - - 3,972 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 49 433 7,539 - - - 8,021 65 Materials & Supplies: - - - - 35 73 - - 108 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 9 4 109 - - - 122 68 Cash & Bank Balances - - 43 0 0 - - - 43 69 Property, Payroll & Income Taxes Accrued: - - (5) (34) (578) - - (617) 70 TOTAL RATE BASE - - 348 6,767 17,281 20,656 - - 45,053 71 % of Rate Base 0.0000% 0.0000% 0.7735% 15.0212% 38.3568% 45.8485% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: AGG TRNSPT - SMALL GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 43,841 43,841 7 Storage Cost 44,299 44,299 8 Total - Production - - 43,841 44,299 - - - - 88,140 910 Transmission: 17,431 1,553 18,984 11 Distribution: 123,156 36,743 159,898 12 Customer Accounts and Services: - 13 Allocable 104,485 104,485 14 Transport Allocable 197,068 197,068 15 Customer Sales: - - 16 Administrative & General: - - 24,271 17,464 110,858 - 96,605 128,122 377,320 17 Total Operation & Maintenance Expense: - - 68,111 61,763 251,445 38,296 201,090 325,190 945,895 1819 Depreciation & Amort Expense: - - 6,040 25,297 146,517 35,866 - - 213,720 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 116 42 142 1,199 696 - 2,195 23 Retirement Benefits - FED 1,384 506 1,696 14,314 8,314 - 26,214 24 IBS Payroll Tax 824 301 1,009 8,520 4,948 - 15,602 25 Michigan SBT & Real Estate/Property - - 1,342 27,190 70,187 14,797 - - 113,517 26 Misc - Unauthorized Ins. Tax & Franchise - - 7 134 346 73 - - 560 27 Total Taxes Other Than Income Taxes: - - 3,673 28,173 73,381 38,902 13,958 - 158,087 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 1,118 22,657 58,485 12,330 - - 94,589 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 78,942 137,890 529,828 125,393 215,048 325,190 1,412,292 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (169) (3,425) (8,842) (1,864) - - (14,300) 40 Acct 488, Acct 495: Miscellaneous (899) (899) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (169) (3,425) (8,842) (1,864) (899) - (15,199) 4445 Actual Return (Net Operating Income) - - 5,346 108,318 279,608 58,947 - - 452,219 4647 Return Income Deficiency - - 28 571 1,473 310 - - 2,382 4849 Additional Income Taxes on Deficiency: - - 1,246 25,253 65,188 13,743 - - 105,431 5051 REVENUE REQUIREMENTS: - - 85,394 268,606 867,254 196,530 214,149 325,190 1,957,124 5253545556 RATE BASE:57 Utility Plant in Service - - 131,864 1,146,828 5,553,272 1,983,781 - - 8,815,745 58 Accumulated Depreciation - S/L - - (70,559) (545,696) (3,082,682) (1,059,578) - - (4,758,516) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 61,305 601,132 2,470,590 924,203 - - 4,057,230 6162 Gas Stored Underground: - - - 997,893 - - - - 997,893 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 11,095 108,743 2,023,568 - - - 2,143,406 65 Materials & Supplies: - - - - 8,573 1,074 - - 9,647 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 2,144 1,039 26,395 - - - 29,579 68 Cash & Bank Balances - - 10,469 7 103 - - - 10,579 69 Property, Payroll & Income Taxes Accrued: - - (1,096) (8,590) (140,329) - - (150,014) 70 TOTAL RATE BASE - - 83,917 1,700,224 4,388,900 925,277 - - 7,098,319 71 % of Rate Base 0.0000% 0.0000% 1.1822% 23.9525% 61.8301% 13.0352% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: AGG TRNSPT - LARGE GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 519 519 7 Storage Cost 856 856 8 Total - Production - - 519 856 - - - - 1,375 910 Transmission: 206 31 237 11 Distribution: 1,557 239 1,796 12 Customer Accounts and Services: - 13 Allocable 1,949 1,949 14 Transport Allocable 1,187 1,187 15 Customer Sales: - - 16 Administrative & General: - - 287 337 1,402 - 1,802 772 4,601 17 Total Operation & Maintenance Expense: - - 806 1,193 3,165 270 3,751 1,959 11,145 1819 Depreciation & Amort Expense: - - 72 489 1,791 393 - - 2,744 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 1 2 14 8 - 26 23 Retirement Benefits - FED 17 6 20 171 99 - 313 24 IBS Payroll Tax 10 4 12 102 59 - 186 25 Michigan SBT & Real Estate/Property - - 17 525 1,041 199 - - 1,783 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 3 5 1 - - 9 27 Total Taxes Other Than Income Taxes: - - 45 538 1,080 487 167 - 2,317 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 14 438 867 166 - - 1,485 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 937 2,658 6,903 1,316 3,918 1,959 17,692 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (3) (97) (192) (37) - - (328) 40 Acct 488, Acct 495: Miscellaneous (5) (5) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (3) (97) (192) (37) (5) - (333) 4445 Actual Return (Net Operating Income) - - 243 7,388 14,633 2,802 - - 25,066 4647 Return Income Deficiency - - (174) (5,284) (10,465) (2,004) - - (17,927) 4849 Additional Income Taxes on Deficiency: - - 16 488 967 185 - - 1,656 5051 REVENUE REQUIREMENTS: - - 1,020 5,153 11,846 2,262 3,913 1,959 26,153 5253545556 RATE BASE:57 Utility Plant in Service - - 1,561 22,159 67,589 27,512 - - 118,821 58 Accumulated Depreciation - S/L - - (835) (10,544) (37,597) (15,058) - - (64,034) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 726 11,615 29,992 12,454 - - 54,787 6162 Gas Stored Underground: - - - 19,282 - - - - 19,282 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 221 2,101 36,322 - - - 38,644 65 Materials & Supplies: - - - - 101 6 - - 107 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 25 20 313 - - - 358 68 Cash & Bank Balances - - 124 0 1 - - - 125 69 Property, Payroll & Income Taxes Accrued: - - (13) (166) (1,656) - - (1,835) 70 TOTAL RATE BASE - - 1,083 32,853 65,074 12,460 - - 111,469 71 % of Rate Base 0.0000% 0.0000% 0.9713% 29.4724% 58.3780% 11.1783% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: SPECIAL CONTRACT GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 1,597 1,597 5 Gas Supply Acquisition Cost 11 11 6 Production Demand 6 6 7 Storage Cost 25 25 8 Total - Production 1,597 11 6 25 - - - - 1,640 910 Transmission: 2 0 3 11 Distribution: 18 83 102 12 Customer Accounts and Services: - 13 Allocable 5,274 5,274 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 6 3 10 16 - 4,877 - 4,913 17 Total Operation & Maintenance Expense: 1,597 18 9 35 37 84 10,151 - 11,931 1819 Depreciation & Amort Expense: - - 1 14 21 53 - - 90 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 0 0 0 0 0 0 - 0 23 Retirement Benefits - FED 0 0 0 0 3 2 - 5 24 IBS Payroll Tax 0 0 0 0 2 1 - 3 25 Michigan SBT & Real Estate/Property - - 0 15 29 18 - - 62 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 0 0 0 - - 0 27 Total Taxes Other Than Income Taxes: - 0 0 16 30 22 3 - 71 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 0 13 24 15 - - 52 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 1,597 18 11 77 112 174 10,154 - 12,143 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (3) (236) (446) (272) - - (957) 40 Acct 488, Acct 495: Miscellaneous (2) (2) 41 Acct 495: Customer Penalities & Gas True-up (7) (7) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (7) - (3) (236) (446) (272) (2) - (966) 4445 Actual Return (Net Operating Income) - - 369 28,145 53,207 32,467 - - 114,188 4647 Return Income Deficiency - - (368) (28,084) (53,091) (32,396) - - (113,940) 4849 Additional Income Taxes on Deficiency: - - 0 14 27 16 - - 58 5051 REVENUE REQUIREMENTS: 1,590 18 9 (83) (192) (11) 10,152 - 11,483 5253545556 RATE BASE:57 Utility Plant in Service - - 18 644 794 2,222 - - 3,678 58 Accumulated Depreciation - S/L - - (10) (307) (441) (1,122) - - (1,880) 59 Construction Work in Progress - - - - - - - - - 60 Net Plant in Service - - 9 338 352 1,100 - - 1,799 6162 Gas Stored Underground: - - - 561 - - - - 561 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 3 61 1,469 - - - 1,533 65 Materials & Supplies: - - - - 1 2 - - 3 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - - 1 4 - - - 4 68 Cash & Bank Balances - - 1 0 0 - - - 1 69 Property, Payroll & Income Taxes Accrued: - - - (5) (19) - - (24) 70 TOTAL RATE BASE - - 13 955 1,806 1,102 - - 3,877 71 % of Rate Base 0.0000% 0.0000% 0.3230% 24.6483% 46.5960% 28.4327% 0.0000% 0.0000% 100.0000%





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Page 1 of 4

Mic

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Page 2 of 4

Mic

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n G

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Page 3 of 4

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Mic

higa

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mis

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n G

as U

tiliti

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ME

TER

SIZ

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tal

Rat

e C

lass

Rat

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ule

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0 M

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00

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per

iod

endi

ng D

ecem

ber 3

1, 2

012

11



Page 1 of 1

Michigan Public Service CommissionMichigan Gas Utilities CorporationProjected Cost of Service Allocation StudyAccount 381: Average Cost Per MeterProjected Test Year Ending December 31, 2014

[A] [B] [C] [D] [E] [F]

Line No. YEAR ACCT RATE SCHEDULEMeter & Device

Replacement Cost Meter CountCOST PER

METER

1 2012 381 Residential $32,342,562 125,530 257.65$ 23 Transp. Agg - Residential $8,131 39 208.49$ 45 Customer Choice-Residential $4,918,853 24,958 197.09$ 67 Multi Family - I $18,929 113 167.51$ 89 Multi Family - II $155,418 204 761.85$ 1011 Multi Family - III $34,548 13 2,657.54$ 1213 Multi Family - IV $13,884 10 1,388.40$ 1415 GS - Small $13,483,873 8,072 1,670.45$ 1617 GS - Large $32,425 19 1,706.58$ 1819 TR-1 $232,459 103 2,256.88$ 2021 TR-2 $87,428 39 2,241.74$ 2223 TR-3 $12,281 7 1,754.43$ 2425 Guardian Glass $1,453 1 1,453.00$ 2627 Transp.Agg - GS-Small $603,211 509 1,185.09$ 2829 Customer Choice-GS Small $7,496,350 4,674 1,603.84$ 3031 Transp. Agg - GS-Large $4,041 3 1,347.00$ 3233 Customer Choice - Multi Family - I $2,256 23 98.09$ 3435 Customer Choice - Multi Family - II $5,067 12 422.25$ 3637 Customer Choice - Multi Family - III $14,146 4 3,536.50$ 3839 Customer Choice - Multi Family - IV $3,855 3 1,285.00$ 4041 NOTE: This data is based upon the historical period ending December 31, 2012



Page 1 of 1

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Page 1 of 1


Account 367: Transmission Gas Mains Regression Analysis

Historical Year Ending December 31, 2012

Summarized Input Data

MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOST

STEEL 2 4 $24 $374 277 2,261,558 $13.04 $39.54

2 4 $35 $474 86 2,261,558 $13.04 $39.54

2 4 $3 $33 5 2,261,558 $13.04 $39.54

2 4 $619 $6,257 650 2,261,558 $13.04 $39.54

2 4 $2,918 $28,467 3,009 2,261,558 $13.04 $39.54

2 4 $119 $1,034 60 2,261,558 $13.04 $39.54

2 4 $7,597 $64,979 1,581 2,261,558 $13.04 $39.54

2 4 $52 $425 24 2,261,558 $13.04 $39.54

2 4 $1,171 $6,513 432 2,261,558 $13.04 $39.54

2 4 $979 $4,735 231 2,261,558 $13.04 $39.54

2 4 $7,521 $31,921 395 2,261,558 $13.04 $39.54

2 4 $63 $238 19 2,261,558 $13.04 $39.54

2 4 $44,129 $119,106 2,235 2,261,558 $13.04 $39.54

2 4 $3,106 $7,227 310 2,261,558 $13.04 $39.54

2 4 $665 $1,555 94 2,261,558 $13.04 $39.54

2 4 $55,621 $125,712 344 2,261,558 $13.04 $39.54

2 4 $669 $1,353 45 2,261,558 $13.04 $39.54

2 4 $1,514 $3,288 359 2,261,558 $13.04 $39.54

2 4 $595 $1,248 53 2,261,558 $13.04 $39.54

2 4 $250 $458 27 2,261,558 $13.04 $39.54

2 4 $7,733 $13,915 346 2,261,558 $13.04 $39.54

2 4 $6,024 $10,666 270 2,261,558 $13.04 $39.54

2 4 $785 $1,102 49 2,261,558 $13.04 $39.54

4 16 $216 $5,721 916 2,261,558 $9.68 $40.09

4 16 $4,792 $74,007 20,317 2,261,558 $9.68 $40.09

4 16 $573 $8,166 263 2,261,558 $9.68 $40.09

4 16 $2,744 $37,216 2,589 2,261,558 $9.68 $40.09

4 16 $14,784 $174,888 11,406 2,261,558 $9.68 $40.09

4 16 $623 $6,932 25 2,261,558 $9.68 $40.09

4 16 $7,484 $80,016 15,113 2,261,558 $9.68 $40.09

4 16 $3,195 $32,901 1,241 2,261,558 $9.68 $40.09

4 16 $69,434 $701,917 26,954 2,261,558 $9.68 $40.09

4 16 $239,374 $2,334,949 99,745 2,261,558 $9.68 $40.09

4 16 $4,591 $44,007 7,669 2,261,558 $9.68 $40.09

4 16 $354,004 $3,174,618 22,487 2,261,558 $9.68 $40.09

4 16 $311,107 $2,745,639 105,301 2,261,558 $9.68 $40.09

4 16 $129,330 $1,123,554 23,837 2,261,558 $9.68 $40.09

4 16 $33,642 $287,766 2,596 2,261,558 $9.68 $40.09

4 16 $121,368 $992,362 19,794 2,261,558 $9.68 $40.09

4 16 $183,947 $1,382,091 25,984 2,261,558 $9.68 $40.09

4 16 $16,569 $115,152 4,376 2,261,558 $9.68 $40.09

4 16 $24,698 $143,044 2,699 2,261,558 $9.68 $40.09

4 16 $1,358 $7,549 186 2,261,558 $9.68 $40.09

4 16 $20,482 $99,026 1,772 2,261,558 $9.68 $40.09

4 16 $11,540 $40,608 834 2,261,558 $9.68 $40.09

4 16 $82,909 $263,414 258 2,261,558 $9.68 $40.09

4 16 $262,718 $709,083 4,925 2,261,558 $9.68 $40.09

4 16 $136,190 $327,800 3,695 2,261,558 $9.68 $40.09

4 16 $78,743 $173,048 23,693 2,261,558 $9.68 $40.09

4 16 $95,491 $222,147 3,512 2,261,558 $9.68 $40.09

4 16 $552,100 $1,284,382 22,796 2,261,558 $9.68 $40.09

4 16 $2,347 $5,482 123 2,261,558 $9.68 $40.09

4 16 $53,767 $121,522 124 2,261,558 $9.68 $40.09

4 16 $22,505 $49,457 983 2,261,558 $9.68 $40.09

4 16 $108,486 $220,945 1,873 2,261,558 $9.68 $40.09

4 16 $117,724 $255,681 10,387 2,261,558 $9.68 $40.09

4 16 $148,495 $320,012 7,527 2,261,558 $9.68 $40.09

4 16 $7,790 $16,405 265 2,261,558 $9.68 $40.09

4 16 $4,382 $9,193 148 2,261,558 $9.68 $40.09

4 16 $33,090 $63,882 1,216 2,261,558 $9.68 $40.09

4 16 $429 $806 14 2,261,558 $9.68 $40.09

4 16 $7,944 $14,481 87 2,261,558 $9.68 $40.09

4 16 $67,889 $122,157 1,123 2,261,558 $9.68 $40.09

4 16 $1,022,654 $1,810,814 16,913 2,261,558 $9.68 $40.09

4 16 $7,163 $12,408 119 2,261,558 $9.68 $40.09

4 16 $551,934 $774,938 12,820 2,261,558 $9.68 $40.09

4 16 $2,552 $3,293 23 2,261,558 $9.68 $40.09

6 36 $1,292 $21,131 2,959 2,261,558 $11.66 $56.74



Page 1 of 8






STEEL 6 36 $17,722 $273,700 41,652 2,261,558 $11.66 $56.74

6 36 $43,923 $595,642 22,364 2,261,558 $11.66 $56.74

6 36 $123,256 $1,370,608 2,763 2,261,558 $11.66 $56.74

6 36 $5,897 $63,057 6,431 2,261,558 $11.66 $56.74

6 36 $187,545 $1,931,021 39,315 2,261,558 $11.66 $56.74

6 36 $1,046,801 $10,582,206 219,401 2,261,558 $11.66 $56.74

6 36 $518,964 $5,062,176 107,044 2,261,558 $11.66 $56.74

6 36 $913 $8,754 824 2,261,558 $11.66 $56.74

6 36 $3,670 $32,908 126 2,261,558 $11.66 $56.74

6 36 $1,526 $13,464 279 2,261,558 $11.66 $56.74

6 36 $180,298 $1,542,238 7,503 2,261,558 $11.66 $56.74

6 36 $125,235 $870,381 17,871 2,261,558 $11.66 $56.74

6 36 $24,336 $152,032 1,570 2,261,558 $11.66 $56.74

6 36 $1,864 $10,794 110 2,261,558 $11.66 $56.74

6 36 $135,409 $752,873 10,003 2,261,558 $11.66 $56.74

6 36 $11,418 $55,205 535 2,261,558 $11.66 $56.74

6 36 $26,858 $94,514 1,048 2,261,558 $11.66 $56.74

6 36 $106,985 $288,755 1,083 2,261,558 $11.66 $56.74

6 36 $164,561 $396,086 2,411 2,261,558 $11.66 $56.74

6 36 $65,436 $152,227 1,300 2,261,558 $11.66 $56.74

6 36 $402,042 $939,224 11,348 2,261,558 $11.66 $56.74

6 36 $332,002 $729,618 7,837 2,261,558 $11.66 $56.74

6 36 $677,850 $1,460,793 12,176 2,261,558 $11.66 $56.74

6 36 $120,646 $262,029 5,748 2,261,558 $11.66 $56.74

6 36 $342,047 $742,884 8,356 2,261,558 $11.66 $56.74

6 36 $114,382 $246,498 3,131 2,261,558 $11.66 $56.74

6 36 $25,316 $53,116 465 2,261,558 $11.66 $56.74

6 36 $138,791 $267,943 2,754 2,261,558 $11.66 $56.74

6 36 $91,838 $172,506 1,708 2,261,558 $11.66 $56.74

6 36 $113,637 $204,474 1,015 2,261,558 $11.66 $56.74

6 36 $621,912 $1,101,219 5,554 2,261,558 $11.66 $56.74

6 36 $321,294 $556,509 2,869 2,261,558 $11.66 $56.74

6 36 $374,529 $469,005 5,145 2,261,558 $11.66 $56.74

8 64 $6,452 $105,507 14,773 2,261,558 $14.89 $73.22

8 64 $2,342 $36,174 5,363 2,261,558 $14.89 $73.22

8 64 $365,155 $5,487,197 90,490 2,261,558 $14.89 $73.22

8 64 $442,682 $6,311,062 109,703 2,261,558 $14.89 $73.22

8 64 $173,367 $2,351,031 88,321 2,261,558 $14.89 $73.22

8 64 $2,132 $25,223 888 2,261,558 $14.89 $73.22

8 64 $242,039 $2,492,104 50,739 2,261,558 $14.89 $73.22

8 64 $191,904 $1,871,910 39,607 2,261,558 $14.89 $73.22

8 64 $4,732 $41,760 865 2,261,558 $14.89 $73.22

8 64 $457,140 $3,971,404 45,500 2,261,558 $14.89 $73.22

8 64 $337,610 $2,887,867 14,070 2,261,558 $14.89 $73.22

8 64 $213,441 $1,745,195 18,797 2,261,558 $14.89 $73.22

8 64 $241,008 $1,810,820 18,384 2,261,558 $14.89 $73.22

8 64 $7,884 $54,794 1,125 2,261,558 $14.89 $73.22

8 64 $524,698 $3,277,887 33,830 2,261,558 $14.89 $73.22

8 64 $376,754 $2,182,036 26,977 2,261,558 $14.89 $73.22

8 64 $195,592 $1,087,491 14,449 2,261,558 $14.89 $73.22

8 64 $384,221 $1,857,624 17,967 2,261,558 $14.89 $73.22

8 64 $248,360 $1,054,106 2,599 2,261,558 $14.89 $73.22

8 64 $213,978 $497,789 4,249 2,261,558 $14.89 $73.22

8 64 $772,512 $1,746,002 959 2,261,558 $14.89 $73.22

8 64 $587,701 $1,291,548 13,873 2,261,558 $14.89 $73.22

8 64 $413,858 $836,746 5,549 2,261,558 $14.89 $73.22

8 64 $116,073 $236,397 1,082 2,261,558 $14.89 $73.22

8 64 $25,553 $55,498 1,218 2,261,558 $14.89 $73.22

8 64 $97,219 $211,147 2,375 2,261,558 $14.89 $73.22

8 64 $1,205,110 $2,597,060 32,989 2,261,558 $14.89 $73.22

8 64 $1,852,826 $3,887,439 34,025 2,261,558 $14.89 $73.22

8 64 $208,913 $403,319 4,145 2,261,558 $14.89 $73.22

8 64 $11,772 $21,531 236 2,261,558 $14.89 $73.22

8 64 $213,436 $377,932 1,906 2,261,558 $14.89 $73.22

8 64 $91,439 $117,959 433 2,261,558 $14.89 $73.22

8 64 $67,374 $77,718 52 2,261,558 $14.89 $73.22

8 64 $104,750 $117,658 706 2,261,558 $14.89 $73.22

10 100 $22,259 $334,483 5,516 2,261,558 $15.00 $73.51



Page 2 of 8






STEEL 10 100 $488,652 $6,966,418 121,093 2,261,558 $15.00 $73.51

10 100 $22,497 $195,446 2,239 2,261,558 $15.00 $73.51

10 100 $395,910 $1,914,138 18,514 2,261,558 $15.00 $73.51

10 100 $537,332 $2,032,358 32,382 2,261,558 $15.00 $73.51

10 100 $885,054 $3,114,494 34,530 2,261,558 $15.00 $73.51

10 100 $463,735 $1,386,219 12,380 2,261,558 $15.00 $73.51

10 100 $571,398 $1,155,263 7,660 2,261,558 $15.00 $73.51

10 100 $21,283 $43,346 198 2,261,558 $15.00 $73.51

10 100 $3,431 $7,395 94 2,261,558 $15.00 $73.51

10 100 $3,462 $7,291 64 2,261,558 $15.00 $73.51

10 100 $3,646 $6,848 68 2,261,558 $15.00 $73.51

10 100 $108,532 $121,907 400 2,261,558 $15.00 $73.51

12 144 $384 $5,212 196 2,261,558 $25.50 $105.00

12 144 $49,839 $644,431 1,860 2,261,558 $25.50 $105.00

12 144 $442,638 $5,593,335 59,188 2,261,558 $25.50 $105.00

12 144 $124,770 $1,387,443 2,796 2,261,558 $25.50 $105.00

12 144 $1,781,890 $10,320,110 105,114 2,261,558 $25.50 $105.00

12 144 $11,635 $64,688 859 2,261,558 $25.50 $105.00

12 144 $799,010 $1,627,288 7,450 2,261,558 $25.50 $105.00

12 144 $3,231,589 $6,964,200 75,807 2,261,558 $25.50 $105.00

12 144 $1,220 $2,356 24 2,261,558 $25.50 $105.00

12 144 $29,808 $55,991 555 2,261,558 $25.50 $105.00

$31,935,545 $147,377,744 2,261,558



Page 3 of 8




Relating Current Cost Per Foot to Pipe Diameter Squared

Eliminating Outliers

DEPENDENT VARIABLE: UHWICOST

SUM OF MEAN

SOURCE DF SQUARES SQUARE F VALUE PROB>F

MODEL 1 765874703.3 765874703.3 1,812 0.0001

ERROR 156 65954087.51 422782.6123

C TOTAL 157 831828790.8

ROOT MSE 650.21736 R‐SQUARE 0.9207

DEP MEAN 65.16646 ADJ R‐SQ 0.9202

C.V. 997.7791

PARAMETER STANDARD T FOR H0:

VARIABLE DF ESTIMATE ERROR PARAMETER=0 PROB > |T|

INTERCEP 1 37.729283 0.776214 48.6070000 0.0001

SQSIZE 1 0.46687 0.01096922 42.562 0.0001

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐

ANALYSIS OF VARIANCE

PARAMETER ESTIMATES



Page 4 of 8






DEP VAR PREDICT STD ERR STD ERR STUDENT COOK'S

OBS WEIGHT UHWICOST VALUE PREDICT RESIDUAL RESIDUAL RESIDUAL ‐2‐1‐0 1 2 D

1 277 39.545 39.5968 0.74 ‐0.0518 39.061 ‐0.001 | | | 0

2 86 39.545 39.5968 0.74 ‐0.0518 70.111 ‐0.001 | | | 0

3 5 39.545 39.5968 0.74 ‐0.0518 290.785 0 | | | 0

4 650 39.545 39.5968 0.74 ‐0.0518 25.493 ‐0.002 | | | 0

5 3009 39.545 39.5968 0.74 ‐0.0518 11.83 ‐0.004 | | | 0

6 60 39.545 39.5968 0.74 ‐0.0518 83.939 ‐0.001 | | | 0

7 1581 39.545 39.5968 0.74 ‐0.0518 16.336 ‐0.003 | | | 0

8 24 39.545 39.5968 0.74 ‐0.0518 132.723 0 | | | 0

9 432 39.545 39.5968 0.74 ‐0.0518 31.275 ‐0.002 | | | 0

10 231 39.545 39.5968 0.74 ‐0.0518 42.775 ‐0.001 | | | 0

11 395 39.545 39.5968 0.74 ‐0.0518 32.708 ‐0.002 | | | 0

12 19 39.545 39.5968 0.74 ‐0.0518 149.168 0 | | | 0

13 2235 39.545 39.5968 0.74 ‐0.0518 13.734 ‐0.004 | | | 0

14 310 39.545 39.5968 0.74 ‐0.0518 36.922 ‐0.001 | | | 0

15 94 39.545 39.5968 0.74 ‐0.0518 67.061 ‐0.001 | | | 0

16 344 39.545 39.5968 0.74 ‐0.0518 35.05 ‐0.001 | | | 0

17 45 39.545 39.5968 0.74 ‐0.0518 96.926 ‐0.001 | | | 0

18 359 39.545 39.5968 0.74 ‐0.0518 34.309 ‐0.002 | | | 0

19 53 39.545 39.5968 0.74 ‐0.0518 89.311 ‐0.001 | | | 0

20 27 39.545 39.5968 0.74 ‐0.0518 125.132 0 | | | 0

21 346 39.545 39.5968 0.74 ‐0.0518 34.948 ‐0.001 | | | 0

22 270 39.545 39.5968 0.74 ‐0.0518 39.564 ‐0.001 | | | 0

23 49 39.545 39.5968 0.74 ‐0.0518 92.885 ‐0.001 | | | 0

24 916 40.0872 45.1992 0.638 ‐5.112 21.474 ‐0.238 | | | 0

25 20317 40.0872 45.1992 0.638 ‐5.112 4.517 ‐1.132 | **| | 0.013

26 263 40.0872 45.1992 0.638 ‐5.112 40.089 ‐0.128 | | | 0

27 2589 40.0872 45.1992 0.638 ‐5.112 12.763 ‐0.401 | | | 0

28 11406 40.0872 45.1992 0.638 ‐5.112 6.055 ‐0.844 | *| | 0.004

29 25 40.0872 45.1992 0.638 ‐5.112 130.042 ‐0.039 | | | 0

30 15113 40.0872 45.1992 0.638 ‐5.112 5.25 ‐0.974 | *| | 0.007

31 1241 40.0872 45.1992 0.638 ‐5.112 18.446 ‐0.277 | | | 0

32 26954 40.0872 45.1992 0.638 ‐5.112 3.909 ‐1.308 | **| | 0.023

33 99745 40.0872 45.1992 0.638 ‐5.112 1.957 ‐2.612 | *****| | 0.362

34 7669 40.0872 45.1992 0.638 ‐5.112 7.397 ‐0.691 | *| | 0.002

35 22487 40.0872 45.1992 0.638 ‐5.112 4.289 ‐1.192 | **| | 0.016

36 105301 40.0872 45.1992 0.638 ‐5.112 1.899 ‐2.691 | *****| | 0.409

37 23837 40.0872 45.1992 0.638 ‐5.112 4.163 ‐1.228 | **| | 0.018

38 2596 40.0872 45.1992 0.638 ‐5.112 12.746 ‐0.401 | | | 0

39 19794 40.0872 45.1992 0.638 ‐5.112 4.577 ‐1.117 | **| | 0.012

40 25984 40.0872 45.1992 0.638 ‐5.112 3.983 ‐1.283 | **| | 0.021

41 4376 40.0872 45.1992 0.638 ‐5.112 9.809 ‐0.521 | *| | 0.001

42 2699 40.0872 45.1992 0.638 ‐5.112 12.499 ‐0.409 | | | 0

43 186 40.0872 45.1992 0.638 ‐5.112 47.672 ‐0.107 | | | 0

44 1772 40.0872 45.1992 0.638 ‐5.112 15.433 ‐0.331 | | | 0

45 834 40.0872 45.1992 0.638 ‐5.112 22.506 ‐0.227 | | | 0

46 258 40.0872 45.1992 0.638 ‐5.112 40.476 ‐0.126 | | | 0

47 4925 40.0872 45.1992 0.638 ‐5.112 9.243 ‐0.553 | *| | 0.001

48 3695 40.0872 45.1992 0.638 ‐5.112 10.678 ‐0.479 | | | 0

49 23693 40.0872 45.1992 0.638 ‐5.112 4.176 ‐1.224 | **| | 0.017

50 3512 40.0872 45.1992 0.638 ‐5.112 10.953 ‐0.467 | | | 0

51 22796 40.0872 45.1992 0.638 ‐5.112 4.259 ‐1.2 | **| | 0.016

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



Page 5 of 8








52 123 40.0872 45.1992 0.638 ‐5.112 58.625 ‐0.087 | | | 0

53 124 40.0872 45.1992 0.638 ‐5.112 58.388 ‐0.088 | | | 0

54 983 40.0872 45.1992 0.638 ‐5.112 20.729 ‐0.247 | | | 0

55 1873 40.0872 45.1992 0.638 ‐5.112 15.011 ‐0.341 | | | 0

56 10387 40.0872 45.1992 0.638 ‐5.112 6.348 ‐0.805 | *| | 0.003

57 7527 40.0872 45.1992 0.638 ‐5.112 7.467 ‐0.685 | *| | 0.002

58 265 40.0872 45.1992 0.638 ‐5.112 39.937 ‐0.128 | | | 0

59 148 40.0872 45.1992 0.638 ‐5.112 53.444 ‐0.096 | | | 0

60 1216 40.0872 45.1992 0.638 ‐5.112 18.635 ‐0.274 | | | 0

61 14 40.0872 45.1992 0.638 ‐5.112 173.777 ‐0.029 | | | 0

62 87 40.0872 45.1992 0.638 ‐5.112 69.708 ‐0.073 | | | 0

63 1123 40.0872 45.1992 0.638 ‐5.112 19.392 ‐0.264 | | | 0

64 16913 40.0872 45.1992 0.638 ‐5.112 4.959 ‐1.031 | **| | 0.009

65 119 40.0872 45.1992 0.638 ‐5.112 59.602 ‐0.086 | | | 0

66 12820 40.0872 45.1992 0.638 ‐5.112 5.707 ‐0.896 | *| | 0.005

67 23 40.0872 45.1992 0.638 ‐5.112 135.578 ‐0.038 | | | 0

68 2959 56.7436 54.5366 0.499 2.207 11.943 0.185 | | | 0

69 41652 56.7436 54.5366 0.499 2.207 3.147 0.701 | |* | 0.006

70 22364 56.7436 54.5366 0.499 2.207 4.319 0.511 | |* | 0.002

71 2763 56.7436 54.5366 0.499 2.207 12.36 0.179 | | | 0

72 6431 56.7436 54.5366 0.499 2.207 8.093 0.273 | | | 0

73 39315 56.7436 54.5366 0.499 2.207 3.241 0.681 | |* | 0.006

74 219401 56.7436 54.5366 0.499 2.207 1.295 1.704 | |*** | 0.216

75 107044 56.7436 54.5366 0.499 2.207 1.924 1.147 | |** | 0.044

76 824 56.7436 54.5366 0.499 2.207 22.646 0.097 | | | 0

77 126 56.7436 54.5366 0.499 2.207 57.924 0.038 | | | 0

78 279 56.7436 54.5366 0.499 2.207 38.924 0.057 | | | 0

79 7503 56.7436 54.5366 0.499 2.207 7.49 0.295 | | | 0

80 17871 56.7436 54.5366 0.499 2.207 4.838 0.456 | | | 0.001

81 1570 56.7436 54.5366 0.499 2.207 16.402 0.135 | | | 0

82 110 56.7436 54.5366 0.499 2.207 61.994 0.036 | | | 0

83 10003 56.7436 54.5366 0.499 2.207 6.482 0.34 | | | 0

84 535 56.7436 54.5366 0.499 2.207 28.107 0.079 | | | 0

85 1048 56.7436 54.5366 0.499 2.207 20.079 0.11 | | | 0

86 1083 56.7436 54.5366 0.499 2.207 19.752 0.112 | | | 0

87 2411 56.7436 54.5366 0.499 2.207 13.233 0.167 | | | 0

88 1300 56.7436 54.5366 0.499 2.207 18.027 0.122 | | | 0

89 11348 56.7436 54.5366 0.499 2.207 6.083 0.363 | | | 0

90 7837 56.7436 54.5366 0.499 2.207 7.328 0.301 | | | 0

91 12176 56.7436 54.5366 0.499 2.207 5.871 0.376 | | | 0.001

92 5748 56.7436 54.5366 0.499 2.207 8.562 0.258 | | | 0

93 8356 56.7436 54.5366 0.499 2.207 7.096 0.311 | | | 0

94 3131 56.7436 54.5366 0.499 2.207 11.61 0.19 | | | 0

95 465 56.7436 54.5366 0.499 2.207 30.149 0.073 | | | 0

96 2754 56.7436 54.5366 0.499 2.207 12.38 0.178 | | | 0

97 1708 56.7436 54.5366 0.499 2.207 15.725 0.14 | | | 0

98 1015 56.7436 54.5366 0.499 2.207 20.403 0.108 | | | 0

99 5554 56.7436 54.5366 0.499 2.207 8.711 0.253 | | | 0

100 2869 56.7436 54.5366 0.499 2.207 12.129 0.182 | | | 0

101 5145 56.7436 54.5366 0.499 2.207 9.051 0.244 | | | 0

102 14773 73.2222 67.609 0.436 5.6132 5.332 1.053 | |** | 0.004

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



Page 6 of 8








103 5363 73.2222 67.609 0.436 5.6132 8.868 0.633 | |* | 0

104 90490 73.2222 67.609 0.436 5.6132 2.117 2.651 | |***** | 0.149

105 109703 73.2222 67.609 0.436 5.6132 1.914 2.933 | |***** | 0.223

106 88321 73.2222 67.609 0.436 5.6132 2.144 2.618 | |***** | 0.142

107 888 73.2222 67.609 0.436 5.6132 21.816 0.257 | | | 0

108 50739 73.2222 67.609 0.436 5.6132 2.853 1.967 | |*** | 0.045

109 39607 73.2222 67.609 0.436 5.6132 3.238 1.734 | |*** | 0.027

110 865 73.2222 67.609 0.436 5.6132 22.104 0.254 | | | 0

111 45500 73.2222 67.609 0.436 5.6132 3.017 1.861 | |*** | 0.036

112 14070 73.2222 67.609 0.436 5.6132 5.464 1.027 | |** | 0.003

113 18797 73.2222 67.609 0.436 5.6132 4.722 1.189 | |** | 0.006

114 18384 73.2222 67.609 0.436 5.6132 4.776 1.175 | |** | 0.006

115 1125 73.2222 67.609 0.436 5.6132 19.381 0.29 | | | 0

116 33830 73.2222 67.609 0.436 5.6132 3.508 1.6 | |*** | 0.02

117 26977 73.2222 67.609 0.436 5.6132 3.935 1.427 | |** | 0.013

118 14449 73.2222 67.609 0.436 5.6132 5.392 1.041 | |** | 0.004

119 17967 73.2222 67.609 0.436 5.6132 4.831 1.162 | |** | 0.006

120 2599 73.2222 67.609 0.436 5.6132 12.747 0.44 | | | 0

121 4249 73.2222 67.609 0.436 5.6132 9.966 0.563 | |* | 0

122 959 73.2222 67.609 0.436 5.6132 20.992 0.267 | | | 0

123 13873 73.2222 67.609 0.436 5.6132 5.503 1.02 | |** | 0.003

124 5549 73.2222 67.609 0.436 5.6132 8.718 0.644 | |* | 0.001

125 1082 73.2222 67.609 0.436 5.6132 19.762 0.284 | | | 0

126 1218 73.2222 67.609 0.436 5.6132 18.626 0.301 | | | 0

127 2375 73.2222 67.609 0.436 5.6132 13.335 0.421 | | | 0

128 32989 73.2222 67.609 0.436 5.6132 3.553 1.58 | |*** | 0.019

129 34025 73.2222 67.609 0.436 5.6132 3.498 1.605 | |*** | 0.02

130 4145 73.2222 67.609 0.436 5.6132 10.09 0.556 | |* | 0

131 236 73.2222 67.609 0.436 5.6132 42.323 0.133 | | | 0

132 1906 73.2222 67.609 0.436 5.6132 14.887 0.377 | | | 0

133 433 73.2222 67.609 0.436 5.6132 31.244 0.18 | | | 0

134 52 73.2222 67.609 0.436 5.6132 90.168 0.062 | | | 0

135 706 73.2222 67.609 0.436 5.6132 24.467 0.229 | | | 0

136 5516 73.5126 84.4163 0.626 ‐10.9037 8.732 ‐1.249 | **| | 0.004

137 121093 73.5126 84.4163 0.626 ‐10.9037 1.761 ‐6.193 |******| | 2.422

138 2239 73.5126 84.4163 0.626 ‐10.9037 13.727 ‐0.794 | *| | 0.001

139 18514 73.5126 84.4163 0.626 ‐10.9037 4.738 ‐2.302 | ****| | 0.046

140 32382 73.5126 84.4163 0.626 ‐10.9037 3.559 ‐3.064 |******| | 0.145

141 34530 73.5126 84.4163 0.626 ‐10.9037 3.443 ‐3.167 |******| | 0.166

142 12380 73.5126 84.4163 0.626 ‐10.9037 5.81 ‐1.877 | ***| | 0.02

143 7660 73.5126 84.4163 0.626 ‐10.9037 7.403 ‐1.473 | **| | 0.008

144 198 73.5126 84.4163 0.626 ‐10.9037 46.205 ‐0.236 | | | 0

145 94 73.5126 84.4163 0.626 ‐10.9037 67.062 ‐0.163 | | | 0

146 64 73.5126 84.4163 0.626 ‐10.9037 81.275 ‐0.134 | | | 0

147 68 73.5126 84.4163 0.626 ‐10.9037 78.848 ‐0.138 | | | 0

148 400 73.5126 84.4163 0.626 ‐10.9037 32.505 ‐0.335 | | | 0

149 196 105 105 1.03 0.0844 46.433 0.002 | | | 0

150 1860 105 105 1.03 0.0844 15.041 0.006 | | | 0

151 59188 105 105 1.03 0.0844 2.466 0.034 | | | 0

152 2796 105 105 1.03 0.0844 12.254 0.007 | | | 0

153 105114 105 105 1.03 0.0844 1.721 0.049 | | | 0

154 859 105 105 1.03 0.0844 22.161 0.004 | | | 0

155 7450 105 105 1.03 0.0844 7.462 0.011 | | | 0

156 75807 105 105 1.03 0.0844 2.125 0.04 | | | 0

157 24 105 105 1.03 0.0844 132.721 0.001 | | | 0

158 555 105 105 1.03 0.0844 27.581 0.003 | | | 0

SUM OF RESIDUALS 0

SUM OF SQUARED RESIDUALS 65954087.513

PREDICTED RESID SS (PRESS) 73646187.970

NOTE: THE ABOVE STATISTICS USE OBSERVATION WEIGHTS OR FREQUENCIES.

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



Page 7 of 8




MATERIAL _MODEL_ _TYPE_ _DEPVAR_ _RMSE_ INTERCEP SQSIZE UHWICOST

STEEL MODEL1 PARMS UHWICOST 650.217 37.7293 0.46687 ‐1

MINIMUM MINIMUM

SYSTEM SYSTEM AT

CURRENT COST CURRENT

MATERIAL QUANTITY PER UNIT COST

STEEL 2,261,558 37.7293 85,326,962

MINIMUM MINIMUM DEMAND

SYSTEM AT TOTAL AT SYSTEM AT RELATED

CURRENT CURRENT CURRENT COST CURRENT COST

COST COST PERCENT PERCENT

85,326,962 147,377,744 0.57897 0.42103


Current Cost Estimates


Estimation of Minimum Cost of Gas Transmission Mains


Estimation of Percentage of Minimum Cost of Gas Transmission Mains



Page 8 of 8


Account 376: Distribution Gas Mains Regression Analysis



MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTPLASTIC 0.75 0.563 $730.0 $9,360.0 1,414 10,587,131 $1.33 $8.34

0.75 0.563 $12.0 $80.0 23 10,587,131 $1.33 $8.34

0.75 0.563 $456.0 $2,438.0 170 10,587,131 $1.33 $8.34

0.75 0.563 $1,175.0 $2,954.0 171 10,587,131 $1.33 $8.34

1 1 $777.0 $9,962.0 1,505 10,587,131 $7.47 $17.47

1 1 $273.0 $1,522.0 529 10,587,131 $7.47 $17.47

1 1 $586.0 $3,132.0 219 10,587,131 $7.47 $17.47

1 1 $21,063.0 $108,053.0 4,172 10,587,131 $7.47 $17.47

1 1 $588.0 $2,695.0 117 10,587,131 $7.47 $17.47

1 1 $7,787.0 $31,455.0 1,250 10,587,131 $7.47 $17.47

1 1 $7,188.0 $27,314.0 1,308 10,587,131 $7.47 $17.47

1 1 $1,048.0 $3,734.0 207 10,587,131 $7.47 $17.47

1 1 $2,250.0 $7,447.0 834 10,587,131 $7.47 $17.47

1 1 $508.0 $1,393.0 106 10,587,131 $7.47 $17.47

1 1 $6,243.0 $14,047.0 536 10,587,131 $7.47 $17.47

1 1 $2,808.0 $6,131.0 393 10,587,131 $7.47 $17.47

1 1 $1,215.0 $2,534.0 196 10,587,131 $7.47 $17.47

1 1 $3,692.0 $7,399.0 550 10,587,131 $7.47 $17.47

1 1 $5,095.0 $8,741.0 1,428 10,587,131 $7.47 $17.47

1 1 $3,533.0 $5,809.0 604 10,587,131 $7.47 $17.47

1 1 $10,037.0 $16,040.0 1,741 10,587,131 $7.47 $17.47

1 1 $421.0 $659.0 81 10,587,131 $7.47 $17.47

1 1 $5,538.0 $8,164.0 942 10,587,131 $7.47 $17.47

1 1 $3,504.0 $5,021.0 511 10,587,131 $7.47 $17.47

1 1 $381.0 $510.0 38 10,587,131 $7.47 $17.47

1 1 $41,208.0 $46,666.0 1,694 10,587,131 $7.47 $17.47

1 1 $19,949.0 $22,055.0 530 10,587,131 $7.47 $17.47

1.25 1.563 $2,608.0 $33,444.0 4,987 10,587,131 $5.00 $18.10

1.25 1.563 $6,766.0 $36,156.0 2,529 10,587,131 $5.00 $18.10

1.25 1.563 $8,598.0 $44,107.0 1,703 10,587,131 $5.00 $18.10

1.25 1.563 $1,325.0 $6,071.0 264 10,587,131 $5.00 $18.10

1.25 1.563 $87,877.0 $354,966.0 14,118 10,587,131 $5.00 $18.10

1.25 1.563 $28,616.0 $108,739.0 5,206 10,587,131 $5.00 $18.10

1.25 1.563 $2,476.0 $8,820.0 489 10,587,131 $5.00 $18.10

1.25 1.563 $4,110.0 $13,602.0 950 10,587,131 $5.00 $18.10

1.25 1.563 $6,418.0 $19,481.0 1,392 10,587,131 $5.00 $18.10

1.25 1.563 $3,684.0 $10,108.0 767 10,587,131 $5.00 $18.10

1.25 1.563 $1,730.0 $4,350.0 252 10,587,131 $5.00 $18.10

1.25 1.563 $3,705.0 $8,640.0 390 10,587,131 $5.00 $18.10

1.25 1.563 $8,288.0 $18,649.0 712 10,587,131 $5.00 $18.10

1.25 1.563 $9,928.0 $21,672.0 1,386 10,587,131 $5.00 $18.10

1.25 1.563 $718.0 $1,339.0 124 10,587,131 $5.00 $18.10

1.25 1.563 $3,392.0 $6,149.0 613 10,587,131 $5.00 $18.10

1.25 1.563 $1,190.0 $2,106.0 302 10,587,131 $5.00 $18.10

1.25 1.563 $377.0 $619.0 65 10,587,131 $5.00 $18.10

1.25 1.563 $855.0 $1,366.0 148 10,587,131 $5.00 $18.10

1.25 1.563 $9,977.0 $15,605.0 1,927 10,587,131 $5.00 $18.10

1.25 1.563 $2,612.0 $3,988.0 504 10,587,131 $5.00 $18.10

1.25 1.563 $5,319.0 $5,661.0 1,255 10,587,131 $5.00 $18.10

2 4 $5.0 $331.0 10 10,587,131 $6.60 $13.14

2 4 $4.0 $58.0 7 10,587,131 $6.60 $13.14

2 4 $11.0 $157.0 22 10,587,131 $6.60 $13.14

2 4 $47,271.0 $606,247.0 90,885 10,587,131 $6.60 $13.14

2 4 $54.0 $656.0 104 10,587,131 $6.60 $13.14

2 4 $19.0 $207.0 36 10,587,131 $6.60 $13.14

2 4 $12.0 $119.0 23 10,587,131 $6.60 $13.14

2 4 $16.0 $155.0 31 10,587,131 $6.60 $13.14



Page 1 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTPLASTIC 2 4 $1,378.0 $12,854.0 2,670 10,587,131 $6.60 $13.14

2 4 $28.0 $251.0 50 10,587,131 $6.60 $13.14

2 4 $1.0 $4.0 1 10,587,131 $6.60 $13.14

2 4 $315.0 $2,275.0 610 10,587,131 $6.60 $13.14

2 4 $581.0 $4,084.0 1,126 10,587,131 $6.60 $13.14

2 4 $811.0 $5,473.0 292 10,587,131 $6.60 $13.14

2 4 $27.0 $180.0 53 10,587,131 $6.60 $13.14

2 4 $346.0 $2,063.0 670 10,587,131 $6.60 $13.14

2 4 $39,243.0 $218,822.0 75,102 10,587,131 $6.60 $13.14

2 4 $495,360.0 $2,647,080.0 184,935 10,587,131 $6.60 $13.14

2 4 $1,336,278.0 $6,855,108.0 264,655 10,587,131 $6.60 $13.14

2 4 $710,231.0 $3,253,111.0 140,655 10,587,131 $6.60 $13.14

2 4 $866,576.0 $3,500,421.0 138,386 10,587,131 $6.60 $13.14

2 4 $809,211.0 $3,075,001.0 147,099 10,587,131 $6.60 $13.14

2 4 $672,559.0 $2,395,991.0 132,503 10,587,131 $6.60 $13.14

2 4 $798,516.0 $2,642,831.0 184,368 10,587,131 $6.60 $13.14

2 4 $1,158,074.0 $3,515,338.0 251,165 10,587,131 $6.60 $13.14

2 4 $751,542.0 $2,061,716.0 156,437 10,587,131 $6.60 $13.14

2 4 $906,783.0 $2,280,292.0 131,830 10,587,131 $6.60 $13.14

2 4 $473,509.0 $1,104,137.0 50,008 10,587,131 $6.60 $13.14

2 4 $671,076.0 $1,509,921.0 59,272 10,587,131 $6.60 $13.14

2 4 $753,528.0 $1,659,054.0 94,199 10,587,131 $6.60 $13.14

2 4 $555,915.0 $1,213,550.0 78,577 10,587,131 $6.60 $13.14

2 4 $789,928.0 $1,695,535.0 120,364 10,587,131 $6.60 $13.14

2 4 $832,488.0 $1,736,042.0 133,948 10,587,131 $6.60 $13.14

2 4 $1,136,749.0 $2,277,938.0 169,286 10,587,131 $6.60 $13.14

2 4 $974,548.0 $1,817,975.0 168,549 10,587,131 $6.60 $13.14

2 4 $1,257,566.0 $2,279,616.0 227,226 10,587,131 $6.60 $13.14

2 4 $704,188.0 $1,245,683.0 178,710 10,587,131 $6.60 $13.14

2 4 $837,811.0 $1,466,885.0 308,712 10,587,131 $6.60 $13.14

2 4 $1,247,520.0 $2,140,393.0 349,154 10,587,131 $6.60 $13.14

2 4 $1,485,619.0 $2,490,596.0 203,727 10,587,131 $6.60 $13.14

2 4 $923,775.0 $1,518,898.0 157,690 10,587,131 $6.60 $13.14

2 4 $1,105,234.0 $1,766,308.0 192,188 10,587,131 $6.60 $13.14

2 4 $1,166,673.0 $1,824,706.0 224,931 10,587,131 $6.60 $13.14

2 4 $892,635.0 $1,362,863.0 172,423 10,587,131 $6.60 $13.14

2 4 $1,514,261.0 $2,271,392.0 199,733 10,587,131 $6.60 $13.14

2 4 $1,157,234.0 $1,705,923.0 198,250 10,587,131 $6.60 $13.14

2 4 $1,117,071.0 $1,600,719.0 162,676 10,587,131 $6.60 $13.14

2 4 $1,690,246.0 $2,369,116.0 103,283 10,587,131 $6.60 $13.14

2 4 $1,824,407.0 $2,522,697.0 151,071 10,587,131 $6.60 $13.14

2 4 $1,719,346.0 $2,302,936.0 171,354 10,587,131 $6.60 $13.14

2 4 $2,008,372.0 $2,519,059.0 172,017 10,587,131 $6.60 $13.14

2 4 $1,864,549.0 $2,224,451.0 177,713 10,587,131 $6.60 $13.14

2 4 $1,538,679.0 $1,742,478.0 132,675 10,587,131 $6.60 $13.14

2 4 $1,050,088.0 $1,160,980.0 73,956 10,587,131 $6.60 $13.14

2 4 $880,719.0 $912,745.0 63,575 10,587,131 $6.60 $13.14

2 4 $1,168,347.0 $1,243,489.0 84,584 10,587,131 $6.60 $13.14

2 4 $1,063,214.0 $1,097,442.0 57,144 10,587,131 $6.60 $13.14

2 4 $228,587.0 $228,587.0 9,020 10,587,131 $6.60 $13.14

3 9 $119.0 $204.0 33 10,587,131 $3.59 $6.17

4 16 $16,184.0 $207,556.0 29,181 10,587,131 $11.62 $22.49

4 16 $61.0 $750.0 119 10,587,131 $11.62 $22.49

4 16 $157.0 $1,750.0 304 10,587,131 $11.62 $22.49

4 16 $90.0 $903.0 174 10,587,131 $11.62 $22.49

4 16 $40.0 $390.0 78 10,587,131 $11.62 $22.49

4 16 $43.0 $400.0 83 10,587,131 $11.62 $22.49



Page 2 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTPLASTIC 4 16 $17.0 $153.0 33 10,587,131 $11.62 $22.49

4 16 $5.0 $34.0 9 10,587,131 $11.62 $22.49

4 16 $66.0 $442.0 127 10,587,131 $11.62 $22.49

4 16 $8.0 $51.0 15 10,587,131 $11.62 $22.49

4 16 $83.0 $517.0 160 10,587,131 $11.62 $22.49

4 16 $813.0 $4,536.0 1,576 10,587,131 $11.62 $22.49

4 16 $327,300.0 $1,749,011.0 55,897 10,587,131 $11.62 $22.49

4 16 $1,155,251.0 $5,926,440.0 114,407 10,587,131 $11.62 $22.49

4 16 $770,651.0 $3,529,856.0 80,122 10,587,131 $11.62 $22.49

4 16 $434,725.0 $1,756,015.0 35,148 10,587,131 $11.62 $22.49

4 16 $729,953.0 $2,773,821.0 66,330 10,587,131 $11.62 $22.49

4 16 $498,903.0 $1,777,343.0 49,232 10,587,131 $11.62 $22.49

4 16 $788,463.0 $2,609,557.0 91,029 10,587,131 $11.62 $22.49

4 16 $1,115,510.0 $3,386,133.0 120,999 10,587,131 $11.62 $22.49

4 16 $1,562,870.0 $4,287,445.0 162,663 10,587,131 $11.62 $22.49

4 16 $874,003.0 $2,197,861.0 63,532 10,587,131 $11.62 $22.49

4 16 $564,730.0 $1,316,849.0 29,759 10,587,131 $11.62 $22.49

4 16 $614,589.0 $1,382,826.0 26,670 10,587,131 $11.62 $22.49

4 16 $568,873.0 $1,252,496.0 35,441 10,587,131 $11.62 $22.49

4 16 $949,310.0 $2,072,324.0 66,649 10,587,131 $11.62 $22.49

4 16 $718,229.0 $1,541,637.0 54,646 10,587,131 $11.62 $22.49

4 16 $760,858.0 $1,586,668.0 61,206 10,587,131 $11.62 $22.49

4 16 $662,403.0 $1,327,394.0 49,326 10,587,131 $11.62 $22.49

4 16 $621,729.0 $1,159,807.0 54,804 10,587,131 $11.62 $22.49

4 16 $701,146.0 $1,270,982.0 63,419 10,587,131 $11.62 $22.49

4 16 $1,355,312.0 $2,397,500.0 171,820 10,587,131 $11.62 $22.49

4 16 $1,760,825.0 $3,082,945.0 325,396 10,587,131 $11.62 $22.49

4 16 $3,498,716.0 $6,002,814.0 495,208 10,587,131 $11.62 $22.49

4 16 $1,763,611.0 $2,956,641.0 120,333 10,587,131 $11.62 $22.49

4 16 $2,100,535.0 $3,453,765.0 179,541 10,587,131 $11.62 $22.49

4 16 $1,472,357.0 $2,353,020.0 125,679 10,587,131 $11.62 $22.49

4 16 $1,756,348.0 $2,746,971.0 168,701 10,587,131 $11.62 $22.49

4 16 $1,213,087.0 $1,852,123.0 114,792 10,587,131 $11.62 $22.49

4 16 $1,284,300.0 $1,926,450.0 81,773 10,587,131 $11.62 $22.49

4 16 $1,646,260.0 $2,426,815.0 140,148 10,587,131 $11.62 $22.49

4 16 $1,088,622.0 $1,559,953.0 78,135 10,587,131 $11.62 $22.49

4 16 $1,212,462.0 $1,699,434.0 35,395 10,587,131 $11.62 $22.49

4 16 $1,451,694.0 $2,007,329.0 60,054 10,587,131 $11.62 $22.49

4 16 $706,370.0 $946,130.0 34,824 10,587,131 $11.62 $22.49

4 16 $1,126,085.0 $1,412,424.0 51,784 10,587,131 $11.62 $22.49

4 16 $989,584.0 $1,180,597.0 51,555 10,587,131 $11.62 $22.49

4 16 $1,040,626.0 $1,178,457.0 41,555 10,587,131 $11.62 $22.49

4 16 $1,622,922.0 $1,794,308.0 96,168 10,587,131 $11.62 $22.49

4 16 $928,867.0 $962,644.0 49,360 10,587,131 $11.62 $22.49

4 16 $1,418,944.0 $1,510,204.0 97,656 10,587,131 $11.62 $22.49

4 16 $1,815,506.0 $1,873,953.0 99,727 10,587,131 $11.62 $22.49

4 16 $20,790.0 $20,790.0 235 10,587,131 $11.62 $22.49

6 36 $2,272.0 $29,139.0 4,402 10,587,131 $21.97 $29.39

6 36 $12,645.0 $57,920.0 1,263 10,587,131 $21.97 $29.39

6 36 $18,521.0 $27,782.0 1,347 10,587,131 $21.97 $29.39

6 36 $146,390.0 $215,799.0 12,311 10,587,131 $21.97 $29.39

6 36 $4,842.0 $6,938.0 353 10,587,131 $21.97 $29.39

6 36 $269,088.0 $377,165.0 7,855 10,587,131 $21.97 $29.39

6 36 $3,817.0 $5,113.0 1,947 10,587,131 $21.97 $29.39

6 36 $4,916.0 $6,166.0 2,639 10,587,131 $21.97 $29.39

6 36 $191,706.0 $228,710.0 6,451 10,587,131 $21.97 $29.39

6 36 $53,709.0 $60,823.0 1,372 10,587,131 $21.97 $29.39



Page 3 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTPLASTIC 6 36 $43,996.0 $45,595.0 742 10,587,131 $21.97 $29.39

6 36 $112,985.0 $120,251.0 1,266 10,587,131 $21.97 $29.39

6 36 $79,969.0 $82,543.0 1,051 10,587,131 $21.97 $29.39

8 64 $215.0 $368.0 30 10,587,131 $7.15 $12.28

$90,233,844.0 $176,905,622.0 10,587,131

STEEL 0.75 0.563 $55.0 $2,549.0 72 7,456,205 $2.27 $23.07

0.75 0.563 $233.0 $8,807.0 304 7,456,205 $2.27 $23.07

0.75 0.563 $153.0 $2,409.0 189 7,456,205 $2.27 $23.07

0.75 0.563 $301.0 $4,553.0 613 7,456,205 $2.27 $23.07

0.75 0.563 $1,569.0 $22,527.0 1,026 7,456,205 $2.27 $23.07

0.75 0.563 $1,060.0 $13,585.0 484 7,456,205 $2.27 $23.07

0.75 0.563 $9.0 $103.0 8 7,456,205 $2.27 $23.07

0.75 0.563 $112.0 $582.0 32 7,456,205 $2.27 $23.07

0.75 0.563 $2,902.0 $9,947.0 92 7,456,205 $2.27 $23.07

1 1 $827.0 $40,529.0 1,081 7,456,205 $1.44 $26.22

1 1 $623.0 $30,519.0 814 7,456,205 $1.44 $26.22

1 1 $652.0 $31,944.0 852 7,456,205 $1.44 $26.22

1 1 $217.0 $10,021.0 283 7,456,205 $1.44 $26.22

1 1 $1,368.0 $63,312.0 1,788 7,456,205 $1.44 $26.22

1 1 $819.0 $37,924.0 1,071 7,456,205 $1.44 $26.22

1 1 $57.0 $2,516.0 75 7,456,205 $1.44 $26.22

1 1 $6.0 $232.0 8 7,456,205 $1.44 $26.22

1 1 $373.0 $11,938.0 487 7,456,205 $1.44 $26.22

1 1 $21.0 $558.0 28 7,456,205 $1.44 $26.22

1 1 $31.0 $729.0 40 7,456,205 $1.44 $26.22

1 1 $2,997.0 $67,475.0 3,917 7,456,205 $1.44 $26.22

1 1 $1,058.0 $22,037.0 1,383 7,456,205 $1.44 $26.22

1 1 $466.0 $9,251.0 486 7,456,205 $1.44 $26.22

1 1 $3.0 $58.0 3 7,456,205 $1.44 $26.22

1 1 $259.0 $4,696.0 122 7,456,205 $1.44 $26.22

1 1 $632.0 $10,750.0 518 7,456,205 $1.44 $26.22

1 1 $134.0 $2,192.0 129 7,456,205 $1.44 $26.22

1 1 $128.0 $1,944.0 121 7,456,205 $1.44 $26.22

1 1 $732.0 $10,692.0 233 7,456,205 $1.44 $26.22

1 1 $412.0 $5,924.0 270 7,456,205 $1.44 $26.22

1 1 $384.0 $5,159.0 290 7,456,205 $1.44 $26.22

1 1 $469.0 $6,103.0 423 7,456,205 $1.44 $26.22

1 1 $1,623.0 $18,777.0 919 7,456,205 $1.44 $26.22

1 1 $2,476.0 $22,669.0 749 7,456,205 $1.44 $26.22

1 1 $495.0 $4,293.0 153 7,456,205 $1.44 $26.22

1 1 $393.0 $2,578.0 115 7,456,205 $1.44 $26.22

1 1 $1,185.0 $4,219.0 130 7,456,205 $1.44 $26.22

1 1 $2,711.0 $3,608.0 31 7,456,205 $1.44 $26.22

1 1 $2,329.0 $2,985.0 95 7,456,205 $1.44 $26.22

1.25 1.563 $145.0 $7,124.0 190 7,456,205 $5.39 $28.82

1.25 1.563 $598.0 $33,186.0 781 7,456,205 $5.39 $28.82

1.25 1.563 $456.0 $19,993.0 596 7,456,205 $5.39 $28.82

1.25 1.563 $6.0 $255.0 8 7,456,205 $5.39 $28.82

1.25 1.563 $1,063.0 $40,241.0 1,389 7,456,205 $5.39 $28.82

1.25 1.563 $1,678.0 $43,680.0 2,193 7,456,205 $5.39 $28.82

1.25 1.563 $328.0 $7,812.0 429 7,456,205 $5.39 $28.82

1.25 1.563 $633.0 $14,246.0 827 7,456,205 $5.39 $28.82

1.25 1.563 $261.0 $5,434.0 341 7,456,205 $5.39 $28.82

1.25 1.563 $197.0 $3,914.0 206 7,456,205 $5.39 $28.82

1.25 1.563 $1,103.0 $21,366.0 1,318 7,456,205 $5.39 $28.82



Page 4 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTSTEEL 1.25 1.563 $253.0 $4,585.0 238 7,456,205 $5.39 $28.82

1.25 1.563 $1,167.0 $19,843.0 956 7,456,205 $5.39 $28.82

1.25 1.563 $184.0 $2,998.0 176 7,456,205 $5.39 $28.82

1.25 1.563 $319.0 $4,833.0 652 7,456,205 $5.39 $28.82

1.25 1.563 $2,330.0 $34,050.0 741 7,456,205 $5.39 $28.82

1.25 1.563 $26.0 $377.0 17 7,456,205 $5.39 $28.82

1.25 1.563 $502.0 $6,973.0 229 7,456,205 $5.39 $28.82

1.25 1.563 $278.0 $3,741.0 210 7,456,205 $5.39 $28.82

1.25 1.563 $1,180.0 $15,361.0 1,066 7,456,205 $5.39 $28.82

1.25 1.563 $1,578.0 $20,223.0 720 7,456,205 $5.39 $28.82

1.25 1.563 $418.0 $5,044.0 388 7,456,205 $5.39 $28.82

1.25 1.563 $1,790.0 $20,706.0 1,015 7,456,205 $5.39 $28.82

1.25 1.563 $3,576.0 $38,191.0 2,219 7,456,205 $5.39 $28.82

1.25 1.563 $12,496.0 $125,410.0 3,326 7,456,205 $5.39 $28.82

1.25 1.563 $1,335.0 $12,222.0 403 7,456,205 $5.39 $28.82

1.25 1.563 $636.0 $5,523.0 238 7,456,205 $5.39 $28.82

1.25 1.563 $2,801.0 $18,371.0 820 7,456,205 $5.39 $28.82

1.25 1.563 $375.0 $1,335.0 73 7,456,205 $5.39 $28.82

1.25 1.563 $1,848.0 $5,499.0 105 7,456,205 $5.39 $28.82

1.25 1.563 $347.0 $991.0 100 7,456,205 $5.39 $28.82

1.25 1.563 $85.0 $196.0 3 7,456,205 $5.39 $28.82

1.25 1.563 $1,628.0 $3,569.0 72 7,456,205 $5.39 $28.82

1.25 1.563 $3,672.0 $6,564.0 60 7,456,205 $5.39 $28.82

1.25 1.563 $52,871.0 $70,354.0 588 7,456,205 $5.39 $28.82

1.25 1.563 $23,431.0 $32,694.0 118 7,456,205 $5.39 $28.82

1.25 1.563 $1,677.0 $2,308.0 66 7,456,205 $5.39 $28.82

1.5 2.25 $25.0 $526.0 33 7,456,205 $1.12 $19.64

1.5 2.25 $145.0 $2,460.0 119 7,456,205 $1.12 $19.64

2 4 $106.0 $5,537.0 139 7,456,205 $1.44 $19.61

2 4 $439.0 $21,521.0 574 7,456,205 $1.44 $19.61

2 4 $37.0 $1,800.0 48 7,456,205 $1.44 $19.61

2 4 $1,536.0 $79,950.0 356 7,456,205 $1.44 $19.61

2 4 $696.0 $32,187.0 909 7,456,205 $1.44 $19.61

2 4 $638.0 $29,532.0 815 7,456,205 $1.44 $19.61

2 4 $1,680.0 $77,759.0 2,196 7,456,205 $1.44 $19.61

2 4 $872.0 $38,242.0 1,140 7,456,205 $1.44 $19.61

2 4 $5,451.0 $227,032.0 7,124 7,456,205 $1.44 $19.61

2 4 $1,051.0 $39,807.0 1,374 7,456,205 $1.44 $19.61

2 4 $424.0 $13,581.0 554 7,456,205 $1.44 $19.61

2 4 $2,299.0 $66,023.0 3,004 7,456,205 $1.44 $19.61

2 4 $2,590.0 $69,597.0 3,385 7,456,205 $1.44 $19.61

2 4 $15,768.0 $410,468.0 20,663 7,456,205 $1.44 $19.61

2 4 $7,012.0 $166,882.0 9,164 7,456,205 $1.44 $19.61

2 4 $56,553.0 $1,273,211.0 73,911 7,456,205 $1.44 $19.61

2 4 $53,680.0 $1,117,877.0 67,916 7,456,205 $1.44 $19.61

2 4 $56,039.0 $1,111,449.0 58,394 7,456,205 $1.44 $19.61

2 4 $107,159.0 $2,075,893.0 127,756 7,456,205 $1.44 $19.61

2 4 $90,660.0 $1,641,734.0 85,013 7,456,205 $1.44 $19.61

2 4 $137,101.0 $2,330,723.0 111,976 7,456,205 $1.44 $19.61

2 4 $139,355.0 $2,276,123.0 130,832 7,456,205 $1.44 $19.61

2 4 $125,771.0 $1,976,743.0 152,849 7,456,205 $1.44 $19.61

2 4 $414,152.0 $6,272,518.0 836,584 7,456,205 $1.44 $19.61

2 4 $1,294,273.0 $18,914,553.0 412,603 7,456,205 $1.44 $19.61

2 4 $188,708.0 $2,710,233.0 123,475 7,456,205 $1.44 $19.61

2 4 $303,948.0 $4,219,806.0 139,047 7,456,205 $1.44 $19.61

2 4 $263,614.0 $3,541,778.0 199,445 7,456,205 $1.44 $19.61

2 4 $305,111.0 $3,971,204.0 274,544 7,456,205 $1.44 $19.61



Page 5 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTSTEEL 2 4 $523,701.0 $6,711,427.0 238,647 7,456,205 $1.44 $19.61

2 4 $312,688.0 $3,774,917.0 289,645 7,456,205 $1.44 $19.61

2 4 $524,325.0 $6,066,145.0 296,937 7,456,205 $1.44 $19.61

2 4 $183,579.0 $1,960,528.0 113,606 7,456,205 $1.44 $19.61

2 4 $157,706.0 $1,582,756.0 41,937 7,456,205 $1.44 $19.61

2 4 $22,713.0 $207,909.0 6,865 7,456,205 $1.44 $19.61

2 4 $26,802.0 $232,564.0 8,246 7,456,205 $1.44 $19.61

2 4 $3,232.0 $26,919.0 3,868 7,456,205 $1.44 $19.61

2 4 $3,094.0 $22,412.0 616 7,456,205 $1.44 $19.61

2 4 $6,683.0 $43,832.0 1,956 7,456,205 $1.44 $19.61

2 4 $1,585.0 $8,203.0 453 7,456,205 $1.44 $19.61

2 4 $9,630.0 $46,101.0 2,248 7,456,205 $1.44 $19.61

2 4 $6,349.0 $28,282.0 5,062 7,456,205 $1.44 $19.61

2 4 $4,776.0 $19,217.0 855 7,456,205 $1.44 $19.61

2 4 $1,477.0 $5,443.0 268 7,456,205 $1.44 $19.61

2 4 $2,686.0 $9,563.0 295 7,456,205 $1.44 $19.61

2 4 $2,368.0 $8,429.0 456 7,456,205 $1.44 $19.61

2 4 $4,968.0 $15,734.0 1,613 7,456,205 $1.44 $19.61

2 4 $767.0 $2,324.0 413 7,456,205 $1.44 $19.61

2 4 $20,414.0 $60,730.0 1,168 7,456,205 $1.44 $19.61

2 4 $11,176.0 $32,552.0 1,058 7,456,205 $1.44 $19.61

2 4 $4,497.0 $12,828.0 997 7,456,205 $1.44 $19.61

2 4 $5,174.0 $14,760.0 1,495 7,456,205 $1.44 $19.61

2 4 $11,788.0 $29,756.0 281 7,456,205 $1.44 $19.61

2 4 $2,393.0 $5,968.0 301 7,456,205 $1.44 $19.61

2 4 $4,478.0 $10,812.0 370 7,456,205 $1.44 $19.61

2 4 $3,799.0 $8,965.0 384 7,456,205 $1.44 $19.61

2 4 $49,142.0 $114,025.0 1,452 7,456,205 $1.44 $19.61

2 4 $44,446.0 $95,420.0 1,987 7,456,205 $1.44 $19.61

2 4 $15,938.0 $22,970.0 91 7,456,205 $1.44 $19.61

2 4 $9,135.0 $12,156.0 807 7,456,205 $1.44 $19.61

2 4 $9,905.0 $13,820.0 210 7,456,205 $1.44 $19.61

2 4 ($30,934.0) ($39,643.0) 4 7,456,205 $1.44 $19.61

2 4 $6,964.0 $8,482.0 2 7,456,205 $1.44 $19.61

2 4 $11,812.0 $13,243.0 71 7,456,205 $1.44 $19.61

3 9 $380.0 $18,634.0 497 7,456,205 $1.35 $20.21

3 9 $66.0 $3,224.0 86 7,456,205 $1.35 $20.21

3 9 $1,085.0 $53,165.0 1,418 7,456,205 $1.35 $20.21

3 9 $295.0 $16,402.0 386 7,456,205 $1.35 $20.21

3 9 $674.0 $33,031.0 881 7,456,205 $1.35 $20.21

3 9 $2,368.0 $109,593.0 3,095 7,456,205 $1.35 $20.21

3 9 $7,231.0 $334,621.0 9,450 7,456,205 $1.35 $20.21

3 9 $210.0 $9,192.0 274 7,456,205 $1.35 $20.21

3 9 $402.0 $15,239.0 526 7,456,205 $1.35 $20.21

3 9 $12,617.0 $328,446.0 16,490 7,456,205 $1.35 $20.21

3 9 $1,348.0 $32,093.0 1,756 7,456,205 $1.35 $20.21

3 9 $6,490.0 $146,113.0 8,482 7,456,205 $1.35 $20.21

3 9 $8,145.0 $169,621.0 9,327 7,456,205 $1.35 $20.21

3 9 $11,765.0 $233,333.0 12,258 7,456,205 $1.35 $20.21

3 9 $5,464.0 $105,854.0 6,531 7,456,205 $1.35 $20.21

3 9 $7,657.0 $138,652.0 7,176 7,456,205 $1.35 $20.21

3 9 $3,967.0 $67,435.0 3,252 7,456,205 $1.35 $20.21

3 9 $379.0 $6,190.0 364 7,456,205 $1.35 $20.21

3 9 $1,888.0 $29,679.0 2,335 7,456,205 $1.35 $20.21

3 9 $17,611.0 $266,728.0 35,905 7,456,205 $1.35 $20.21

3 9 $17,251.0 $252,103.0 5,486 7,456,205 $1.35 $20.21

3 9 $3,578.0 $51,394.0 2,341 7,456,205 $1.35 $20.21



Page 6 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTSTEEL 3 9 $17,725.0 $246,086.0 8,105 7,456,205 $1.35 $20.21

3 9 $2,951.0 $39,642.0 2,232 7,456,205 $1.35 $20.21

3 9 $512.0 $6,667.0 463 7,456,205 $1.35 $20.21

3 9 $1,741.0 $15,108.0 536 7,456,205 $1.35 $20.21

3 9 $995.0 $2,840.0 287 7,456,205 $1.35 $20.21

3 9 $56,338.0 $130,724.0 1,665 7,456,205 $1.35 $20.21

4 16 $115.0 $5,624.0 150 7,456,205 $4.63 $48.71

4 16 $976.0 $47,840.0 1,276 7,456,205 $4.63 $48.71

4 16 $1,745.0 $85,521.0 2,281 7,456,205 $4.63 $48.71

4 16 $937.0 $45,890.0 1,224 7,456,205 $4.63 $48.71

4 16 $1,797.0 $88,032.0 2,348 7,456,205 $4.63 $48.71

4 16 $5.0 $248.0 7 7,456,205 $4.63 $48.71

4 16 $941.0 $43,553.0 1,230 7,456,205 $4.63 $48.71

4 16 $3,965.0 $183,493.0 5,182 7,456,205 $4.63 $48.71

4 16 $1,125.0 $52,052.0 1,470 7,456,205 $4.63 $48.71

4 16 $631.0 $27,675.0 825 7,456,205 $4.63 $48.71

4 16 $2.0 $101.0 3 7,456,205 $4.63 $48.71

4 16 $1,797.0 $68,025.0 2,348 7,456,205 $4.63 $48.71

4 16 $216.0 $6,198.0 282 7,456,205 $4.63 $48.71

4 16 $18,348.0 $477,609.0 23,971 7,456,205 $4.63 $48.71

4 16 $12,588.0 $299,602.0 16,452 7,456,205 $4.63 $48.71

4 16 $56,121.0 $1,263,478.0 73,346 7,456,205 $4.63 $48.71

4 16 $88,055.0 $1,833,751.0 114,313 7,456,205 $4.63 $48.71

4 16 $234,555.0 $4,652,011.0 91,010 7,456,205 $4.63 $48.71

4 16 $99,753.0 $1,932,417.0 44,539 7,456,205 $4.63 $48.71

4 16 $324,433.0 $5,875,058.0 113,111 7,456,205 $4.63 $48.71

4 16 $200,463.0 $3,407,878.0 60,876 7,456,205 $4.63 $48.71

4 16 $263,673.0 $4,306,660.0 93,633 7,456,205 $4.63 $48.71

4 16 $174,951.0 $2,749,703.0 80,129 7,456,205 $4.63 $48.71

4 16 $526,866.0 $7,979,627.0 396,420 7,456,205 $4.63 $48.71

4 16 $1,816,963.0 $26,553,163.0 215,566 7,456,205 $4.63 $48.71

4 16 $282,716.0 $4,060,389.0 68,511 7,456,205 $4.63 $48.71

4 16 $271,695.0 $3,772,039.0 45,955 7,456,205 $4.63 $48.71

4 16 $406,858.0 $5,466,330.0 114,009 7,456,205 $4.63 $48.71

4 16 $507,739.0 $6,608,536.0 169,763 7,456,205 $4.63 $48.71

4 16 $528,671.0 $6,775,123.0 89,366 7,456,205 $4.63 $48.71

4 16 $792,776.0 $9,570,758.0 273,172 7,456,205 $4.63 $48.71

4 16 $749,112.0 $8,666,814.0 157,095 7,456,205 $4.63 $48.71

4 16 $304,933.0 $3,256,526.0 70,322 7,456,205 $4.63 $48.71

4 16 $402,839.0 $4,042,947.0 39,717 7,456,205 $4.63 $48.71

4 16 $199,634.0 $1,827,417.0 23,342 7,456,205 $4.63 $48.71

4 16 $148,567.0 $1,289,132.0 16,746 7,456,205 $4.63 $48.71

4 16 $26,452.0 $220,344.0 11,522 7,456,205 $4.63 $48.71

4 16 $44,359.0 $321,312.0 3,275 7,456,205 $4.63 $48.71

4 16 $3,137.0 $20,573.0 340 7,456,205 $4.63 $48.71

4 16 $5,871.0 $35,959.0 632 7,456,205 $4.63 $48.71

4 16 $29,596.0 $168,861.0 2,884 7,456,205 $4.63 $48.71

4 16 $243,423.0 $1,259,450.0 25,920 7,456,205 $4.63 $48.71

4 16 $85,156.0 $407,671.0 7,368 7,456,205 $4.63 $48.71

4 16 $64,135.0 $285,694.0 18,933 7,456,205 $4.63 $48.71

4 16 $92,875.0 $373,743.0 6,173 7,456,205 $4.63 $48.71

4 16 $70,197.0 $258,735.0 4,749 7,456,205 $4.63 $48.71

4 16 $2,370.0 $8,438.0 96 7,456,205 $4.63 $48.71

4 16 $56,299.0 $192,992.0 4,757 7,456,205 $4.63 $48.71

4 16 $2,455.0 $8,417.0 144 7,456,205 $4.63 $48.71

4 16 $42,549.0 $151,465.0 3,036 7,456,205 $4.63 $48.71

4 16 $234,023.0 $802,226.0 2,511 7,456,205 $4.63 $48.71



Page 7 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTSTEEL 4 16 $5,490.0 $17,390.0 961 7,456,205 $4.63 $48.71

4 16 $95,356.0 $288,841.0 19,008 7,456,205 $4.63 $48.71

4 16 $25,878.0 $76,986.0 547 7,456,205 $4.63 $48.71

4 16 $30,701.0 $89,418.0 1,235 7,456,205 $4.63 $48.71

4 16 $59,965.0 $171,065.0 4,447 7,456,205 $4.63 $48.71

4 16 $49,801.0 $142,069.0 5,335 7,456,205 $4.63 $48.71

4 16 $14,028.0 $36,630.0 862 7,456,205 $4.63 $48.71

4 16 $136,187.0 $343,770.0 1,204 7,456,205 $4.63 $48.71

4 16 $85,681.0 $213,691.0 3,495 7,456,205 $4.63 $48.71

4 16 $95,622.0 $230,879.0 4,040 7,456,205 $4.63 $48.71

4 16 $23,795.0 $56,152.0 3,882 7,456,205 $4.63 $48.71

4 16 $17,789.0 $41,276.0 195 7,456,205 $4.63 $48.71

4 16 $64,715.0 $141,861.0 1,071 7,456,205 $4.63 $48.71

4 16 $16,738.0 $35,936.0 276 7,456,205 $4.63 $48.71

4 16 $8,873.0 $18,712.0 147 7,456,205 $4.63 $48.71

4 16 $43,523.0 $77,800.0 1,262 7,456,205 $4.63 $48.71

4 16 $40,840.0 $58,857.0 358 7,456,205 $4.63 $48.71

4 16 $238,677.0 $317,601.0 3,649 7,456,205 $4.63 $48.71

4 16 $201,010.0 $280,472.0 4,834 7,456,205 $4.63 $48.71

4 16 $1,107,602.0 $1,525,013.0 29,582 7,456,205 $4.63 $48.71

4 16 $114,201.0 $146,353.0 1,707 7,456,205 $4.63 $48.71

4 16 $35,922.0 $43,748.0 238 7,456,205 $4.63 $48.71

4 16 $71,798.0 $80,495.0 1,400 7,456,205 $4.63 $48.71

6 36 $23,069.0 $1,067,586.0 27,181 7,456,205 $11.18 $73.20

6 36 $6,378.0 $166,035.0 8,336 7,456,205 $11.18 $73.20

6 36 $245.0 $5,827.0 320 7,456,205 $11.18 $73.20

6 36 $390.0 $8,785.0 510 7,456,205 $11.18 $73.20

6 36 $40,172.0 $836,578.0 51,749 7,456,205 $11.18 $73.20

6 36 $40,040.0 $794,127.0 8,344 7,456,205 $11.18 $73.20

6 36 $77,515.0 $1,501,633.0 18,534 7,456,205 $11.18 $73.20

6 36 $36,311.0 $657,541.0 6,807 7,456,205 $11.18 $73.20

6 36 $70,532.0 $1,199,046.0 11,566 7,456,205 $11.18 $73.20

6 36 $76,078.0 $1,242,609.0 14,620 7,456,205 $11.18 $73.20

6 36 $121,211.0 $1,905,068.0 29,978 7,456,205 $11.18 $73.20

6 36 $560,802.0 $8,493,597.0 223,580 7,456,205 $11.18 $73.20

6 36 $57,234.0 $822,002.0 7,490 7,456,205 $11.18 $73.20

6 36 $17,059.0 $236,832.0 1,560 7,456,205 $11.18 $73.20

6 36 $101,632.0 $1,322,809.0 18,347 7,456,205 $11.18 $73.20

6 36 $114,705.0 $1,469,990.0 10,470 7,456,205 $11.18 $73.20

6 36 $44,923.0 $542,328.0 8,359 7,456,205 $11.18 $73.20

6 36 $80,718.0 $933,865.0 9,143 7,456,205 $11.18 $73.20

6 36 $54,695.0 $584,116.0 6,786 7,456,205 $11.18 $73.20

6 36 $43,987.0 $441,460.0 2,342 7,456,205 $11.18 $73.20

6 36 $135,419.0 $1,175,038.0 8,335 7,456,205 $11.18 $73.20

6 36 $168,959.0 $1,407,428.0 40,416 7,456,205 $11.18 $73.20

6 36 $631.0 $4,567.0 25 7,456,205 $11.18 $73.20

6 36 $25,854.0 $169,579.0 1,514 7,456,205 $11.18 $73.20

6 36 $53,254.0 $326,183.0 3,092 7,456,205 $11.18 $73.20

6 36 $94,943.0 $541,695.0 4,824 7,456,205 $11.18 $73.20

6 36 $142,024.0 $734,820.0 8,166 7,456,205 $11.18 $73.20

6 36 $356,713.0 $1,707,710.0 16,662 7,456,205 $11.18 $73.20

6 36 $28,311.0 $126,112.0 4,513 7,456,205 $11.18 $73.20

6 36 $312,256.0 $1,256,567.0 11,204 7,456,205 $11.18 $73.20

6 36 $324,262.0 $1,195,178.0 11,846 7,456,205 $11.18 $73.20

6 36 $106,467.0 $379,005.0 2,332 7,456,205 $11.18 $73.20

6 36 $101,697.0 $348,615.0 4,682 7,456,205 $11.18 $73.20

6 36 $112,828.0 $386,771.0 3,591 7,456,205 $11.18 $73.20



Page 8 of 20





MATERIAL SIZE SQSIZE COST HWICOST QTY TOTQTY UCOST UHWICOSTSTEEL 8 6 36 $331,902.0 $1,181,514.0 12,789 7,456,205 $11.18 $73.20

6 36 $70,200.0 $222,345.0 4,556 7,456,205 $11.18 $73.20

6 36 $13,545.0 $41,028.0 1,458 7,456,205 $11.18 $73.20

6 36 $35,268.0 $104,921.0 403 7,456,205 $11.18 $73.20

6 36 $34,030.0 $99,116.0 739 7,456,205 $11.18 $73.20

6 36 $108,512.0 $309,556.0 4,346 7,456,205 $11.18 $73.20

6 36 $85,239.0 $243,164.0 4,931 7,456,205 $11.18 $73.20

6 36 $650,751.0 $1,699,297.0 21,554 7,456,205 $11.18 $73.20

6 36 $92,502.0 $233,497.0 442 7,456,205 $11.18 $73.20

6 36 $56,874.0 $141,844.0 1,434 7,456,205 $11.18 $73.20

6 36 $361,382.0 $872,553.0 5,965 7,456,205 $11.18 $73.20

6 36 $146,864.0 $346,565.0 2,938 7,456,205 $11.18 $73.20

6 36 $641,589.0 $1,377,432.0 5,784 7,456,205 $11.18 $73.20

6 36 $411,880.0 $855,600.0 597 7,456,205 $11.18 $73.20

6 36 $23,593.0 $42,174.0 296 7,456,205 $11.18 $73.20

6 36 $24,526.0 $32,636.0 2 7,456,205 $11.18 $73.20

6 36 $114,740.0 $160,098.0 727 7,456,205 $11.18 $73.20

6 36 $179,344.0 $229,836.0 2,340 7,456,205 $11.18 $73.20

6 36 $237,076.0 $288,719.0 2,856 7,456,205 $11.18 $73.20

6 36 $85,061.0 $95,364.0 1,191 7,456,205 $11.18 $73.20

8 64 $11,464.0 $207,595.0 2,149 7,456,205 $10.38 $68.22

8 64 $659.0 $10,356.0 163 7,456,205 $10.38 $68.22

8 64 $69,955.0 $1,059,500.0 28,526 7,456,205 $10.38 $68.22

8 64 $63,376.0 $926,183.0 4,031 7,456,205 $10.38 $68.22

8 64 $6,782.0 $86,910.0 619 7,456,205 $10.38 $68.22

8 64 $119,681.0 $1,444,844.0 22,269 7,456,205 $10.38 $68.22

8 64 $184.0 $2,131.0 21 7,456,205 $10.38 $68.22

8 64 $4,393.0 $46,918.0 545 7,456,205 $10.38 $68.22

8 64 $7,232.0 $72,579.0 385 7,456,205 $10.38 $68.22

8 64 $298.0 $2,731.0 18 7,456,205 $10.38 $68.22

8 64 $30,532.0 $264,927.0 1,879 7,456,205 $10.38 $68.22

8 64 $22,480.0 $162,833.0 896 7,456,205 $10.38 $68.22

0 64 $8,774.0 $53,742.0 509 7,456,205 $10.38 $68.22

8 64 $5,408.0 $27,983.0 311 7,456,205 $10.38 $68.22

8 64 $23,783.0 $113,856.0 1,111 7,456,205 $10.38 $68.22

8 64 $78,886.0 $270,420.0 2,511 7,456,205 $10.38 $68.22

8 64 $64,116.0 $228,241.0 2,471 7,456,205 $10.38 $68.22

8 64 $44,379.0 $129,257.0 964 7,456,205 $10.38 $68.22

8 64 $79,604.0 $200,941.0 380 7,456,205 $10.38 $68.22

8 64 $294,513.0 $632,291.0 2,774 7,456,205 $10.38 $68.22

8 64 $6,736.0 $8,204.0 9 7,456,205 $10.38 $68.22

10 100 $181.0 $1,569.0 11 7,456,205 $3.17 $39.39

10 100 $4,190.0 $16,861.0 150 7,456,205 $3.17 $39.39

$26,098,275.0 $254,739,361.0 7,381,860

$116,332,119.0 $431,644,983.0 17,968,991



Page 9 of 20







SUM OF MEAN


MODEL 1 216342439.4 216,342,439 6,656 0.00

ERROR 173 5623245.346 32,504

C TOTAL 174 221965684.8

ROOT MSE 180.2895 R‐SQUARE 0.97470

DEP MEAN 16.7095 ADJ R‐SQ 0.9745

C.V. 1078.96436



INTERCEP 1 10.320942 0.0959281 107.5900 0.0001

SQSIZE 1 0.745224 0.00913454 81.583 0.0001

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=PLASTIC ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



1 1414 8.3417 10.7401 0.092 ‐2.3984 4.794 ‐0.5 | *| | 0

2 23 8.3417 10.7401 0.092 ‐2.3984 37.593 ‐0.064 | | | 0

3 170 8.3417 10.7401 0.092 ‐2.3984 13.827 ‐0.173 | | | 0

4 171 8.3417 10.7401 0.092 ‐2.3984 13.787 ‐0.174 | | | 0

5 1505 17.4687 11.0662 0.089 6.4026 4.646 1.378 | |** | 0

6 529 17.4687 11.0662 0.089 6.4026 7.838 0.817 | |* | 0

7 219 17.4687 11.0662 0.089 6.4026 12.183 0.526 | |* | 0

8 4172 17.4687 11.0662 0.089 6.4026 2.79 2.295 | |**** | 0.003

9 117 17.4687 11.0662 0.089 6.4026 16.668 0.384 | | | 0

10 1250 17.4687 11.0662 0.089 6.4026 5.099 1.256 | |** | 0

11 1308 17.4687 11.0662 0.089 6.4026 4.984 1.285 | |** | 0

12 207 17.4687 11.0662 0.089 6.4026 12.531 0.511 | |* | 0

13 834 17.4687 11.0662 0.089 6.4026 6.242 1.026 | |** | 0

14 106 17.4687 11.0662 0.089 6.4026 17.511 0.366 | | | 0

15 536 17.4687 11.0662 0.089 6.4026 7.787 0.822 | |* | 0

16 393 17.4687 11.0662 0.089 6.4026 9.094 0.704 | |* | 0

17 196 17.4687 11.0662 0.089 6.4026 12.878 0.497 | | | 0

18 550 17.4687 11.0662 0.089 6.4026 7.687 0.833 | |* | 0

19 1428 17.4687 11.0662 0.089 6.4026 4.77 1.342 | |** | 0

20 604 17.4687 11.0662 0.089 6.4026 7.335 0.873 | |* | 0

21 1741 17.4687 11.0662 0.089 6.4026 4.32 1.482 | |** | 0

22 81 17.4687 11.0662 0.089 6.4026 20.032 0.32 | | | 0

23 942 17.4687 11.0662 0.089 6.4026 5.873 1.09 | |** | 0

24 511 17.4687 11.0662 0.089 6.4026 7.975 0.803 | |* | 0

25 38 17.4687 11.0662 0.089 6.4026 29.247 0.219 | | | 0

26 1694 17.4687 11.0662 0.089 6.4026 4.38 1.462 | |** | 0

27 530 17.4687 11.0662 0.089 6.4026 7.831 0.818 | |* | 0

--------------------------------------------------------- MATERIAL=PLASTIC ---------------------------------------------------------


PARAMETER ESTIMATES



Page 10 of 20



28 4987 18.1034 11.4854 0.085 6.618 2.552 2.594 | |***** | 0.004

29 2529 18.1034 11.4854 0.085 6.618 3.584 1.847 | |*** | 0.001

30 1703 18.1034 11.4854 0.085 6.618 4.368 1.515 | |*** | 0

31 264 18.1034 11.4854 0.085 6.618 11.096 0.596 | |* | 0

32 14118 18.1034 11.4854 0.085 6.618 1.515 4.368 | |******| 0.03

33 5206 18.1034 11.4854 0.085 6.618 2.497 2.65 | |***** | 0.004

34 489 18.1034 11.4854 0.085 6.618 8.153 0.812 | |* | 0

35 950 18.1034 11.4854 0.085 6.618 5.849 1.132 | |** | 0

36 1392 18.1034 11.4854 0.085 6.618 4.832 1.37 | |** | 0

37 767 18.1034 11.4854 0.085 6.618 6.509 1.017 | |** | 0

38 252 18.1034 11.4854 0.085 6.618 11.357 0.583 | |* | 0

39 390 18.1034 11.4854 0.085 6.618 9.129 0.725 | |* | 0

40 712 18.1034 11.4854 0.085 6.618 6.756 0.98 | |* | 0

41 1386 18.1034 11.4854 0.085 6.618 4.842 1.367 | |** | 0

42 124 18.1034 11.4854 0.085 6.618 16.19 0.409 | | | 0

43 613 18.1034 11.4854 0.085 6.618 7.281 0.909 | |* | 0

44 302 18.1034 11.4854 0.085 6.618 10.374 0.638 | |* | 0

45 65 18.1034 11.4854 0.085 6.618 22.362 0.296 | | | 0

46 148 18.1034 11.4854 0.085 6.618 14.819 0.447 | | | 0

47 1927 18.1034 11.4854 0.085 6.618 4.106 1.612 | |*** | 0.001

48 504 18.1034 11.4854 0.085 6.618 8.03 0.824 | |* | 0

49 1255 18.1034 11.4854 0.085 6.618 5.088 1.301 | |** | 0

50 10 13.1445 13.3018 0.069 ‐0.1574 57.013 ‐0.003 | | | 0

51 7 13.1445 13.3018 0.069 ‐0.1574 68.143 ‐0.002 | | | 0

52 22 13.1445 13.3018 0.069 ‐0.1574 38.438 ‐0.004 | | | 0

53 90885 13.1445 13.3018 0.069 ‐0.1574 0.594 ‐0.265 | | | 0

54 104 13.1445 13.3018 0.069 ‐0.1574 17.679 ‐0.009 | | | 0

55 36 13.1445 13.3018 0.069 ‐0.1574 30.048 ‐0.005 | | | 0

56 23 13.1445 13.3018 0.069 ‐0.1574 37.593 ‐0.004 | | | 0

57 31 13.1445 13.3018 0.069 ‐0.1574 32.381 ‐0.005 | | | 0

58 2670 13.1445 13.3018 0.069 ‐0.1574 3.488 ‐0.045 | | | 0

59 50 13.1445 13.3018 0.069 ‐0.1574 25.497 ‐0.006 | | | 0

60 1 13.1445 13.3018 0.069 ‐0.1574 180.289 ‐0.001 | | | 0

61 610 13.1445 13.3018 0.069 ‐0.1574 7.299 ‐0.022 | | | 0

62 1126 13.1445 13.3018 0.069 ‐0.1574 5.372 ‐0.029 | | | 0

63 292 13.1445 13.3018 0.069 ‐0.1574 10.55 ‐0.015 | | | 0

64 53 13.1445 13.3018 0.069 ‐0.1574 24.765 ‐0.006 | | | 0

65 670 13.1445 13.3018 0.069 ‐0.1574 6.965 ‐0.023 | | | 0

66 75102 13.1445 13.3018 0.069 ‐0.1574 0.654 ‐0.241 | | | 0

67 184935 13.1445 13.3018 0.069 ‐0.1574 0.413 ‐0.381 | | | 0.002

68 264655 13.1445 13.3018 0.069 ‐0.1574 0.344 ‐0.458 | | | 0.004

69 140655 13.1445 13.3018 0.069 ‐0.1574 0.476 ‐0.331 | | | 0.001

70 138386 13.1445 13.3018 0.069 ‐0.1574 0.48 ‐0.328 | | | 0.001

71 147099 13.1445 13.3018 0.069 ‐0.1574 0.465 ‐0.338 | | | 0.001

72 132503 13.1445 13.3018 0.069 ‐0.1574 0.49 ‐0.321 | | | 0.001

73 184368 13.1445 13.3018 0.069 ‐0.1574 0.414 ‐0.38 | | | 0.002

74 251165 13.1445 13.3018 0.069 ‐0.1574 0.353 ‐0.446 | | | 0.004

75 156437 13.1445 13.3018 0.069 ‐0.1574 0.451 ‐0.349 | | | 0.001

76 131830 13.1445 13.3018 0.069 ‐0.1574 0.492 ‐0.32 | | | 0.001

77 50008 13.1445 13.3018 0.069 ‐0.1574 0.803 ‐0.196 | | | 0

78 59272 13.1445 13.3018 0.069 ‐0.1574 0.737 ‐0.213 | | | 0

79 94199 13.1445 13.3018 0.069 ‐0.1574 0.583 ‐0.27 | | | 0.001

80 78577 13.1445 13.3018 0.069 ‐0.1574 0.639 ‐0.246 | | | 0

81 120364 13.1445 13.3018 0.069 ‐0.1574 0.515 ‐0.306 | | | 0.001

82 133948 13.1445 13.3018 0.069 ‐0.1574 0.488 ‐0.323 | | | 0.001

83 169286 13.1445 13.3018 0.069 ‐0.1574 0.433 ‐0.364 | | | 0.002

84 168549 13.1445 13.3018 0.069 ‐0.1574 0.434 ‐0.363 | | | 0.002

85 227226 13.1445 13.3018 0.069 ‐0.1574 0.372 ‐0.423 | | | 0.003

86 178710 13.1445 13.3018 0.069 ‐0.1574 0.421 ‐0.374 | | | 0.002

87 308712 13.1445 13.3018 0.069 ‐0.1574 0.317 ‐0.496 | | | 0.006

88 349154 13.1445 13.3018 0.069 ‐0.1574 0.297 ‐0.53 | *| | 0.008

89 203727 13.1445 13.3018 0.069 ‐0.1574 0.393 ‐0.4 | | | 0.002

90 157690 13.1445 13.3018 0.069 ‐0.1574 0.449 ‐0.351 | | | 0.001



Page 11 of 20



91 192188 13.1445 13.3018 0.069 ‐0.1574 0.405 ‐0.388 | | | 0.002

92 224931 13.1445 13.3018 0.069 ‐0.1574 0.374 ‐0.421 | | | 0.003

93 172423 13.1445 13.3018 0.069 ‐0.1574 0.429 ‐0.367 | | | 0.002

94 199733 13.1445 13.3018 0.069 ‐0.1574 0.397 ‐0.396 | | | 0.002

95 198250 13.1445 13.3018 0.069 ‐0.1574 0.399 ‐0.394 | | | 0.002

96 162676 13.1445 13.3018 0.069 ‐0.1574 0.442 ‐0.356 | | | 0.002

97 103283 13.1445 13.3018 0.069 ‐0.1574 0.557 ‐0.283 | | | 0.001

98 151071 13.1445 13.3018 0.069 ‐0.1574 0.459 ‐0.343 | | | 0.001

99 171354 13.1445 13.3018 0.069 ‐0.1574 0.43 ‐0.366 | | | 0.002

100 172017 13.1445 13.3018 0.069 ‐0.1574 0.429 ‐0.367 | | | 0.002

101 177713 13.1445 13.3018 0.069 ‐0.1574 0.422 ‐0.373 | | | 0.002

102 132675 13.1445 13.3018 0.069 ‐0.1574 0.49 ‐0.321 | | | 0.001

103 73956 13.1445 13.3018 0.069 ‐0.1574 0.659 ‐0.239 | | | 0

104 63575 13.1445 13.3018 0.069 ‐0.1574 0.712 ‐0.221 | | | 0

105 84584 13.1445 13.3018 0.069 ‐0.1574 0.616 ‐0.255 | | | 0

106 57144 13.1445 13.3018 0.069 ‐0.1574 0.751 ‐0.21 | | | 0

107 9020 13.1445 13.3018 0.069 ‐0.1574 1.897 ‐0.083 | | | 0

108 33 6.1673 17.028 0.056 ‐10.8607 31.384 ‐0.346 | | | 0

109 29181 22.4937 22.2445 0.088 0.2492 1.052 0.237 | | | 0

110 119 22.4937 22.2445 0.088 0.2492 16.527 0.015 | | | 0

111 304 22.4937 22.2445 0.088 0.2492 10.34 0.024 | | | 0

112 174 22.4937 22.2445 0.088 0.2492 13.667 0.018 | | | 0

113 78 22.4937 22.2445 0.088 0.2492 20.414 0.012 | | | 0

114 83 22.4937 22.2445 0.088 0.2492 19.789 0.013 | | | 0

115 33 22.4937 22.2445 0.088 0.2492 31.384 0.008 | | | 0

116 9 22.4937 22.2445 0.088 0.2492 60.096 0.004 | | | 0

117 127 22.4937 22.2445 0.088 0.2492 15.998 0.016 | | | 0

118 15 22.4937 22.2445 0.088 0.2492 46.55 0.005 | | | 0

119 160 22.4937 22.2445 0.088 0.2492 14.253 0.017 | | | 0

120 1576 22.4937 22.2445 0.088 0.2492 4.541 0.055 | | | 0

121 55897 22.4937 22.2445 0.088 0.2492 0.758 0.329 | | | 0.001

122 114407 22.4937 22.2445 0.088 0.2492 0.526 0.474 | | | 0.003

123 80122 22.4937 22.2445 0.088 0.2492 0.631 0.395 | | | 0.002

124 35148 22.4937 22.2445 0.088 0.2492 0.958 0.26 | | | 0

125 66330 22.4937 22.2445 0.088 0.2492 0.695 0.359 | | | 0.001

126 49232 22.4937 22.2445 0.088 0.2492 0.808 0.308 | | | 0.001

127 91029 22.4937 22.2445 0.088 0.2492 0.591 0.422 | | | 0.002

128 120999 22.4937 22.2445 0.088 0.2492 0.511 0.488 | | | 0.003

129 162663 22.4937 22.2445 0.088 0.2492 0.438 0.568 | |* | 0.006

130 63532 22.4937 22.2445 0.088 0.2492 0.71 0.351 | | | 0.001

131 29759 22.4937 22.2445 0.088 0.2492 1.041 0.239 | | | 0

132 26670 22.4937 22.2445 0.088 0.2492 1.1 0.226 | | | 0

133 35441 22.4937 22.2445 0.088 0.2492 0.954 0.261 | | | 0

134 66649 22.4937 22.2445 0.088 0.2492 0.693 0.36 | | | 0.001

135 54646 22.4937 22.2445 0.088 0.2492 0.766 0.325 | | | 0.001

136 61206 22.4937 22.2445 0.088 0.2492 0.723 0.344 | | | 0.001

137 49326 22.4937 22.2445 0.088 0.2492 0.807 0.309 | | | 0.001

138 54804 22.4937 22.2445 0.088 0.2492 0.765 0.326 | | | 0.001

139 63419 22.4937 22.2445 0.088 0.2492 0.711 0.351 | | | 0.001

140 171820 22.4937 22.2445 0.088 0.2492 0.426 0.585 | |* | 0.007

141 325396 22.4937 22.2445 0.088 0.2492 0.304 0.821 | |* | 0.028

142 495208 22.4937 22.2445 0.088 0.2492 0.241 1.035 | |** | 0.071

143 120333 22.4937 22.2445 0.088 0.2492 0.512 0.486 | | | 0.003

144 179541 22.4937 22.2445 0.088 0.2492 0.416 0.598 | |* | 0.008

145 125679 22.4937 22.2445 0.088 0.2492 0.501 0.497 | | | 0.004

146 168701 22.4937 22.2445 0.088 0.2492 0.43 0.579 | |* | 0.007

147 114792 22.4937 22.2445 0.088 0.2492 0.525 0.475 | | | 0.003

148 81773 22.4937 22.2445 0.088 0.2492 0.624 0.399 | | | 0.002

149 140148 22.4937 22.2445 0.088 0.2492 0.474 0.526 | |* | 0.005

150 78135 22.4937 22.2445 0.088 0.2492 0.639 0.39 | | | 0.001

151 35395 22.4937 22.2445 0.088 0.2492 0.954 0.261 | | | 0

152 60054 22.4937 22.2445 0.088 0.2492 0.73 0.341 | | | 0.001

153 34824 22.4937 22.2445 0.088 0.2492 0.962 0.259 | | | 0



Page 12 of 20



154 51784 22.4937 22.2445 0.088 0.2492 0.787 0.316 | | | 0.001

155 51555 22.4937 22.2445 0.088 0.2492 0.789 0.316 | | | 0.001

156 41555 22.4937 22.2445 0.088 0.2492 0.88 0.283 | | | 0

157 96168 22.4937 22.2445 0.088 0.2492 0.575 0.434 | | | 0.002

158 49360 22.4937 22.2445 0.088 0.2492 0.807 0.309 | | | 0.001

159 97656 22.4937 22.2445 0.088 0.2492 0.57 0.437 | | | 0.002

160 99727 22.4937 22.2445 0.088 0.2492 0.564 0.442 | | | 0.002

161 235 22.4937 22.2445 0.088 0.2492 11.76 0.021 | | | 0

162 4402 29.3948 37.149 0.257 ‐7.7542 2.705 ‐2.866 | *****| | 0.037

163 1263 29.3948 37.149 0.257 ‐7.7542 5.067 ‐1.53 | ***| | 0.003

164 1347 29.3948 37.149 0.257 ‐7.7542 4.906 ‐1.581 | ***| | 0.003

165 12311 29.3948 37.149 0.257 ‐7.7542 1.605 ‐4.833 |******| | 0.299

166 353 29.3948 37.149 0.257 ‐7.7542 9.592 ‐0.808 | *| | 0

167 7855 29.3948 37.149 0.257 ‐7.7542 2.018 ‐3.843 |******| | 0.119

168 1947 29.3948 37.149 0.257 ‐7.7542 4.078 ‐1.902 | ***| | 0.007

169 2639 29.3948 37.149 0.257 ‐7.7542 3.5 ‐2.215 | ****| | 0.013

170 6451 29.3948 37.149 0.257 ‐7.7542 2.23 ‐3.477 |******| | 0.08

171 1372 29.3948 37.149 0.257 ‐7.7542 4.861 ‐1.595 | ***| | 0.004

172 742 29.3948 37.149 0.257 ‐7.7542 6.614 ‐1.172 | **| | 0.001

173 1266 29.3948 37.149 0.257 ‐7.7542 5.061 ‐1.532 | ***| | 0.003

174 1051 29.3948 37.149 0.257 ‐7.7542 5.555 ‐1.396 | **| | 0.002

175 30 12.2753 58.0153 0.509 ‐45.74 32.912 ‐1.39 | **| | 0

SUM OF RESIDUALS 0






Page 13 of 20






‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐


SUM OF MEAN


MODEL 1 2121128859 2,121,128,859 1,864 0.00

ERROR 319 363094262.5 1,138,227

C TOTAL 320 2484223121

ROOT MSE 1,066.8770 R‐SQUARE 0.85380

DEP MEAN 35.1744 ADJ R‐SQ 0.85340

C.V. 3,033.1029



INTERCEP 1 16.856827 0.5781393 29.1570 0.0001

SQSIZE 1 1.557903 0.0360887 43.1690 0.0001

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



1 72 23.0718 17.7331 0.563 5.3387 125.731 0.042 | | | 0

2 304 23.0718 17.7331 0.563 5.3387 61.187 0.087 | | | 0

3 189 23.0718 17.7331 0.563 5.3387 77.602 0.069 | | | 0

4 613 23.0718 17.7331 0.563 5.3387 43.087 0.124 | | | 0

5 1026 23.0718 17.7331 0.563 5.3387 33.303 0.16 | | | 0

6 484 23.0718 17.7331 0.563 5.3387 48.491 0.11 | | | 0

7 8 23.0718 17.7331 0.563 5.3387 377.198 0.014 | | | 0

8 32 23.0718 17.7331 0.563 5.3387 188.598 0.028 | | | 0

9 92 23.0718 17.7331 0.563 5.3387 111.228 0.048 | | | 0

10 1081 26.2208 18.4147 0.552 7.8061 32.444 0.241 | | | 0

11 814 26.2208 18.4147 0.552 7.8061 37.39 0.209 | | | 0

12 852 26.2208 18.4147 0.552 7.8061 36.546 0.214 | | | 0

13 283 26.2208 18.4147 0.552 7.8061 63.417 0.123 | | | 0

14 1788 26.2208 18.4147 0.552 7.8061 25.225 0.309 | | | 0

15 1071 26.2208 18.4147 0.552 7.8061 32.595 0.239 | | | 0

16 75 26.2208 18.4147 0.552 7.8061 123.191 0.063 | | | 0

17 8 26.2208 18.4147 0.552 7.8061 377.198 0.021 | | | 0

18 487 26.2208 18.4147 0.552 7.8061 48.342 0.161 | | | 0

19 28 26.2208 18.4147 0.552 7.8061 201.62 0.039 | | | 0

20 40 26.2208 18.4147 0.552 7.8061 168.687 0.046 | | | 0

21 3917 26.2208 18.4147 0.552 7.8061 17.038 0.458 | | | 0

22 1383 26.2208 18.4147 0.552 7.8061 28.683 0.272 | | | 0

23 486 26.2208 18.4147 0.552 7.8061 48.391 0.161 | | | 0

24 3 26.2208 18.4147 0.552 7.8061 615.961 0.013 | | | 0

25 122 26.2208 18.4147 0.552 7.8061 96.589 0.081 | | | 0

26 518 26.2208 18.4147 0.552 7.8061 46.873 0.167 | | | 0

27 129 26.2208 18.4147 0.552 7.8061 93.932 0.083 | | | 0

28 121 26.2208 18.4147 0.552 7.8061 96.987 0.08 | | | 0

29 233 26.2208 18.4147 0.552 7.8061 69.891 0.112 | | | 0


PARAMETER ESTIMATES



Page 14 of 20

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



30 270 26.2208 18.4147 0.552 7.8061 64.926 0.12 | | | 0

31 290 26.2208 18.4147 0.552 7.8061 62.647 0.125 | | | 0

32 423 26.2208 18.4147 0.552 7.8061 51.87 0.15 | | | 0

33 919 26.2208 18.4147 0.552 7.8061 35.189 0.222 | | | 0

34 749 26.2208 18.4147 0.552 7.8061 38.979 0.2 | | | 0

35 153 26.2208 18.4147 0.552 7.8061 86.25 0.091 | | | 0

36 115 26.2208 18.4147 0.552 7.8061 99.485 0.078 | | | 0

37 130 26.2208 18.4147 0.552 7.8061 93.57 0.083 | | | 0

38 31 26.2208 18.4147 0.552 7.8061 191.616 0.041 | | | 0

39 95 26.2208 18.4147 0.552 7.8061 109.458 0.071 | | | 0

40 190 28.8154 19.2911 0.538 9.5244 77.398 0.123 | | | 0

41 781 28.8154 19.2911 0.538 9.5244 38.172 0.25 | | | 0

42 596 28.8154 19.2911 0.538 9.5244 43.698 0.218 | | | 0

43 8 28.8154 19.2911 0.538 9.5244 377.198 0.025 | | | 0

44 1389 28.8154 19.2911 0.538 9.5244 28.621 0.333 | | | 0

45 2193 28.8154 19.2911 0.538 9.5244 22.776 0.418 | | | 0

46 429 28.8154 19.2911 0.538 9.5244 51.506 0.185 | | | 0

47 827 28.8154 19.2911 0.538 9.5244 37.095 0.257 | | | 0

48 341 28.8154 19.2911 0.538 9.5244 57.772 0.165 | | | 0

49 206 28.8154 19.2911 0.538 9.5244 74.331 0.128 | | | 0

50 1318 28.8154 19.2911 0.538 9.5244 29.382 0.324 | | | 0

51 238 28.8154 19.2911 0.538 9.5244 69.153 0.138 | | | 0

52 956 28.8154 19.2911 0.538 9.5244 34.501 0.276 | | | 0

53 176 28.8154 19.2911 0.538 9.5244 80.417 0.118 | | | 0

54 652 28.8154 19.2911 0.538 9.5244 41.779 0.228 | | | 0

55 741 28.8154 19.2911 0.538 9.5244 39.189 0.243 | | | 0

56 17 28.8154 19.2911 0.538 9.5244 258.755 0.037 | | | 0

57 229 28.8154 19.2911 0.538 9.5244 70.499 0.135 | | | 0

58 210 28.8154 19.2911 0.538 9.5244 73.62 0.129 | | | 0

59 1066 28.8154 19.2911 0.538 9.5244 32.672 0.292 | | | 0

60 720 28.8154 19.2911 0.538 9.5244 39.757 0.24 | | | 0

61 388 28.8154 19.2911 0.538 9.5244 54.16 0.176 | | | 0

62 1015 28.8154 19.2911 0.538 9.5244 33.483 0.284 | | | 0

63 2219 28.8154 19.2911 0.538 9.5244 22.642 0.421 | | | 0

64 3326 28.8154 19.2911 0.538 9.5244 18.491 0.515 | |* | 0

65 403 28.8154 19.2911 0.538 9.5244 53.142 0.179 | | | 0

66 238 28.8154 19.2911 0.538 9.5244 69.153 0.138 | | | 0

67 820 28.8154 19.2911 0.538 9.5244 37.253 0.256 | | | 0

68 73 28.8154 19.2911 0.538 9.5244 124.867 0.076 | | | 0

69 105 28.8154 19.2911 0.538 9.5244 104.115 0.091 | | | 0

70 100 28.8154 19.2911 0.538 9.5244 106.686 0.089 | | | 0

71 3 28.8154 19.2911 0.538 9.5244 615.961 0.015 | | | 0

72 72 28.8154 19.2911 0.538 9.5244 125.732 0.076 | | | 0

73 60 28.8154 19.2911 0.538 9.5244 137.732 0.069 | | | 0

74 588 28.8154 19.2911 0.538 9.5244 43.994 0.216 | | | 0

75 118 28.8154 19.2911 0.538 9.5244 98.213 0.097 | | | 0

76 66 28.8154 19.2911 0.538 9.5244 131.322 0.073 | | | 0

77 33 19.6418 20.3621 0.521 ‐0.7203 185.719 ‐0.004 | | | 0

78 119 19.6418 20.3621 0.521 ‐0.7203 97.799 ‐0.007 | | | 0

79 139 19.611 23.0884 0.482 ‐3.4775 90.49 ‐0.038 | | | 0

80 574 19.611 23.0884 0.482 ‐3.4775 44.528 ‐0.078 | | | 0

81 48 19.611 23.0884 0.482 ‐3.4775 153.99 ‐0.023 | | | 0

82 356 19.611 23.0884 0.482 ‐3.4775 56.542 ‐0.062 | | | 0

83 909 19.611 23.0884 0.482 ‐3.4775 35.383 ‐0.098 | | | 0

84 815 19.611 23.0884 0.482 ‐3.4775 37.368 ‐0.093 | | | 0

85 2196 19.611 23.0884 0.482 ‐3.4775 22.761 ‐0.153 | | | 0

86 1140 19.611 23.0884 0.482 ‐3.4775 31.594 ‐0.11 | | | 0

87 7124 19.611 23.0884 0.482 ‐3.4775 12.631 ‐0.275 | | | 0

88 1374 19.611 23.0884 0.482 ‐3.4775 28.778 ‐0.121 | | | 0

89 554 19.611 23.0884 0.482 ‐3.4775 45.325 ‐0.077 | | | 0

90 3004 19.611 23.0884 0.482 ‐3.4775 19.459 ‐0.179 | | | 0

91 3385 19.611 23.0884 0.482 ‐3.4775 18.331 ‐0.19 | | | 0

92 20663 19.611 23.0884 0.482 ‐3.4775 7.406 ‐0.47 | | | 0

93 9164 19.611 23.0884 0.482 ‐3.4775 11.134 ‐0.312 | | | 0



Page 15 of 20

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



94 73911 19.611 23.0884 0.482 ‐3.4775 3.895 ‐0.893 | *| | 0.006

95 67916 19.611 23.0884 0.482 ‐3.4775 4.065 ‐0.855 | *| | 0.005

96 58394 19.611 23.0884 0.482 ‐3.4775 4.389 ‐0.792 | *| | 0.004

97 127756 19.611 23.0884 0.482 ‐3.4775 2.946 ‐1.181 | **| | 0.019

98 85013 19.611 23.0884 0.482 ‐3.4775 3.627 ‐0.959 | *| | 0.008

99 111976 19.611 23.0884 0.482 ‐3.4775 3.152 ‐1.103 | **| | 0.014

100 130832 19.611 23.0884 0.482 ‐3.4775 2.91 ‐1.195 | **| | 0.02

101 152849 19.611 23.0884 0.482 ‐3.4775 2.686 ‐1.295 | **| | 0.027

102 836584 19.611 23.0884 0.482 ‐3.4775 1.062 ‐3.274 |******| | 1.105

103 412603 19.611 23.0884 0.482 ‐3.4775 1.589 ‐2.188 | ****| | 0.22

104 123475 19.611 23.0884 0.482 ‐3.4775 2.998 ‐1.16 | **| | 0.017

105 139047 19.611 23.0884 0.482 ‐3.4775 2.82 ‐1.233 | **| | 0.022

106 199445 19.611 23.0884 0.482 ‐3.4775 2.34 ‐1.486 | **| | 0.047

107 274544 19.611 23.0884 0.482 ‐3.4775 1.978 ‐1.758 | ***| | 0.092

108 238647 19.611 23.0884 0.482 ‐3.4775 2.13 ‐1.633 | ***| | 0.068

109 289645 19.611 23.0884 0.482 ‐3.4775 1.923 ‐1.809 | ***| | 0.103

110 296937 19.611 23.0884 0.482 ‐3.4775 1.898 ‐1.833 | ***| | 0.108

111 113606 19.611 23.0884 0.482 ‐3.4775 3.128 ‐1.112 | **| | 0.015

112 41937 19.611 23.0884 0.482 ‐3.4775 5.187 ‐0.67 | *| | 0.002

113 6865 19.611 23.0884 0.482 ‐3.4775 12.867 ‐0.27 | | | 0

114 8246 19.611 23.0884 0.482 ‐3.4775 11.739 ‐0.296 | | | 0

115 3868 19.611 23.0884 0.482 ‐3.4775 17.147 ‐0.203 | | | 0

116 616 19.611 23.0884 0.482 ‐3.4775 42.983 ‐0.081 | | | 0

117 1956 19.611 23.0884 0.482 ‐3.4775 24.118 ‐0.144 | | | 0

118 453 19.611 23.0884 0.482 ‐3.4775 50.124 ‐0.069 | | | 0

119 2248 19.611 23.0884 0.482 ‐3.4775 22.497 ‐0.155 | | | 0

120 5062 19.611 23.0884 0.482 ‐3.4775 14.987 ‐0.232 | | | 0

121 855 19.611 23.0884 0.482 ‐3.4775 36.483 ‐0.095 | | | 0

122 268 19.611 23.0884 0.482 ‐3.4775 65.168 ‐0.053 | | | 0

123 295 19.611 23.0884 0.482 ‐3.4775 62.114 ‐0.056 | | | 0

124 456 19.611 23.0884 0.482 ‐3.4775 49.959 ‐0.07 | | | 0

125 1613 19.611 23.0884 0.482 ‐3.4775 26.56 ‐0.131 | | | 0

126 413 19.611 23.0884 0.482 ‐3.4775 52.495 ‐0.066 | | | 0

127 1168 19.611 23.0884 0.482 ‐3.4775 31.213 ‐0.111 | | | 0

128 1058 19.611 23.0884 0.482 ‐3.4775 32.796 ‐0.106 | | | 0

129 997 19.611 23.0884 0.482 ‐3.4775 33.785 ‐0.103 | | | 0

130 1495 19.611 23.0884 0.482 ‐3.4775 27.588 ‐0.126 | | | 0

131 281 19.611 23.0884 0.482 ‐3.4775 63.643 ‐0.055 | | | 0

132 301 19.611 23.0884 0.482 ‐3.4775 61.492 ‐0.057 | | | 0

133 370 19.611 23.0884 0.482 ‐3.4775 55.462 ‐0.063 | | | 0

134 384 19.611 23.0884 0.482 ‐3.4775 54.442 ‐0.064 | | | 0

135 1452 19.611 23.0884 0.482 ‐3.4775 27.994 ‐0.124 | | | 0

136 1987 19.611 23.0884 0.482 ‐3.4775 23.929 ‐0.145 | | | 0

137 91 19.611 23.0884 0.482 ‐3.4775 111.838 ‐0.031 | | | 0

138 807 19.611 23.0884 0.482 ‐3.4775 37.553 ‐0.093 | | | 0

139 210 19.611 23.0884 0.482 ‐3.4775 73.62 ‐0.047 | | | 0

140 4 19.611 23.0884 0.482 ‐3.4775 533.438 ‐0.007 | | | 0

141 2 19.611 23.0884 0.482 ‐3.4775 754.396 ‐0.005 | | | 0

142 71 19.611 23.0884 0.482 ‐3.4775 126.614 ‐0.027 | | | 0

143 497 20.2099 30.878 0.405 ‐10.668 47.854 ‐0.223 | | | 0

144 86 20.2099 30.878 0.405 ‐10.668 115.044 ‐0.093 | | | 0

145 1418 20.2099 30.878 0.405 ‐10.668 28.329 ‐0.377 | | | 0

146 386 20.2099 30.878 0.405 ‐10.668 54.301 ‐0.196 | | | 0

147 881 20.2099 30.878 0.405 ‐10.668 35.942 ‐0.297 | | | 0

148 3095 20.2099 30.878 0.405 ‐10.668 19.173 ‐0.556 | *| | 0

149 9450 20.2099 30.878 0.405 ‐10.668 10.967 ‐0.973 | *| | 0.001

150 274 20.2099 30.878 0.405 ‐10.668 64.451 ‐0.166 | | | 0

151 526 20.2099 30.878 0.405 ‐10.668 46.516 ‐0.229 | | | 0

152 16490 20.2099 30.878 0.405 ‐10.668 8.298 ‐1.286 | **| | 0.002

153 1756 20.2099 30.878 0.405 ‐10.668 25.456 ‐0.419 | | | 0

154 8482 20.2099 30.878 0.405 ‐10.668 11.577 ‐0.921 | *| | 0.001

155 9327 20.2099 30.878 0.405 ‐10.668 11.04 ‐0.966 | *| | 0.001

156 12258 20.2099 30.878 0.405 ‐10.668 9.628 ‐1.108 | **| | 0.001

157 6531 20.2099 30.878 0.405 ‐10.668 13.195 ‐0.808 | *| | 0



Page 16 of 20

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



158 7176 20.2099 30.878 0.405 ‐10.668 12.588 ‐0.847 | *| | 0

159 3252 20.2099 30.878 0.405 ‐10.668 18.704 ‐0.57 | *| | 0

160 364 20.2099 30.878 0.405 ‐10.668 55.918 ‐0.191 | | | 0

161 2335 20.2099 30.878 0.405 ‐10.668 22.075 ‐0.483 | | | 0

162 35905 20.2099 30.878 0.405 ‐10.668 5.616 ‐1.9 | ***| | 0.009

163 5486 20.2099 30.878 0.405 ‐10.668 14.398 ‐0.741 | *| | 0

164 2341 20.2099 30.878 0.405 ‐10.668 22.047 ‐0.484 | | | 0

165 8105 20.2099 30.878 0.405 ‐10.668 11.844 ‐0.901 | *| | 0

166 2232 20.2099 30.878 0.405 ‐10.668 22.579 ‐0.472 | | | 0

167 463 20.2099 30.878 0.405 ‐10.668 49.58 ‐0.215 | | | 0

168 536 20.2099 30.878 0.405 ‐10.668 46.08 ‐0.232 | | | 0

169 287 20.2099 30.878 0.405 ‐10.668 62.974 ‐0.169 | | | 0

170 1665 20.2099 30.878 0.405 ‐10.668 26.143 ‐0.408 | | | 0

171 150 48.7149 41.7833 0.421 6.9316 87.109 0.08 | | | 0

172 1276 48.7149 41.7833 0.421 6.9316 29.864 0.232 | | | 0

173 2281 48.7149 41.7833 0.421 6.9316 22.334 0.31 | | | 0

174 1224 48.7149 41.7833 0.421 6.9316 30.492 0.227 | | | 0

175 2348 48.7149 41.7833 0.421 6.9316 22.013 0.315 | | | 0

176 7 48.7149 41.7833 0.421 6.9316 403.241 0.017 | | | 0

177 1230 48.7149 41.7833 0.421 6.9316 30.417 0.228 | | | 0

178 5182 48.7149 41.7833 0.421 6.9316 14.815 0.468 | | | 0

179 1470 48.7149 41.7833 0.421 6.9316 27.823 0.249 | | | 0

180 825 48.7149 41.7833 0.421 6.9316 37.141 0.187 | | | 0

181 3 48.7149 41.7833 0.421 6.9316 615.962 0.011 | | | 0

182 2348 48.7149 41.7833 0.421 6.9316 22.013 0.315 | | | 0

183 282 48.7149 41.7833 0.421 6.9316 63.53 0.109 | | | 0

184 23971 48.7149 41.7833 0.421 6.9316 6.878 1.008 | |** | 0.002

185 16452 48.7149 41.7833 0.421 6.9316 8.307 0.834 | |* | 0.001

186 73346 48.7149 41.7833 0.421 6.9316 3.917 1.77 | |*** | 0.018

187 114313 48.7149 41.7833 0.421 6.9316 3.127 2.217 | |**** | 0.045

188 91010 48.7149 41.7833 0.421 6.9316 3.511 1.974 | |*** | 0.028

189 44539 48.7149 41.7833 0.421 6.9316 5.038 1.376 | |** | 0.007

190 113111 48.7149 41.7833 0.421 6.9316 3.144 2.205 | |**** | 0.044

191 60876 48.7149 41.7833 0.421 6.9316 4.303 1.611 | |*** | 0.012

192 93633 48.7149 41.7833 0.421 6.9316 3.461 2.003 | |**** | 0.03

193 80129 48.7149 41.7833 0.421 6.9316 3.745 1.851 | |*** | 0.022

194 396420 48.7149 41.7833 0.421 6.9316 1.641 4.223 | |******| 0.588

195 215566 48.7149 41.7833 0.421 6.9316 2.259 3.069 | |******| 0.164

196 68511 48.7149 41.7833 0.421 6.9316 4.054 1.71 | |*** | 0.016

197 45955 48.7149 41.7833 0.421 6.9316 4.959 1.398 | |** | 0.007

198 114009 48.7149 41.7833 0.421 6.9316 3.131 2.214 | |**** | 0.044

199 169763 48.7149 41.7833 0.421 6.9316 2.555 2.713 | |***** | 0.1

200 89366 48.7149 41.7833 0.421 6.9316 3.544 1.956 | |*** | 0.027

201 273172 48.7149 41.7833 0.421 6.9316 1.997 3.471 | |******| 0.268

202 157095 48.7149 41.7833 0.421 6.9316 2.659 2.607 | |***** | 0.085

203 70322 48.7149 41.7833 0.421 6.9316 4.001 1.732 | |*** | 0.017

204 39717 48.7149 41.7833 0.421 6.9316 5.337 1.299 | |** | 0.005

205 23342 48.7149 41.7833 0.421 6.9316 6.97 0.994 | |* | 0.002

206 16746 48.7149 41.7833 0.421 6.9316 8.234 0.842 | |* | 0.001

207 11522 48.7149 41.7833 0.421 6.9316 9.93 0.698 | |* | 0

208 3275 48.7149 41.7833 0.421 6.9316 18.638 0.372 | | | 0

209 340 48.7149 41.7833 0.421 6.9316 57.858 0.12 | | | 0

210 632 48.7149 41.7833 0.421 6.9316 42.436 0.163 | | | 0

211 2884 48.7149 41.7833 0.421 6.9316 19.862 0.349 | | | 0

212 25920 48.7149 41.7833 0.421 6.9316 6.613 1.048 | |** | 0.002

213 7368 48.7149 41.7833 0.421 6.9316 12.422 0.558 | |* | 0

214 18933 48.7149 41.7833 0.421 6.9316 7.742 0.895 | |* | 0.001

215 6173 48.7149 41.7833 0.421 6.9316 13.572 0.511 | |* | 0

216 4749 48.7149 41.7833 0.421 6.9316 15.476 0.448 | | | 0

217 96 48.7149 41.7833 0.421 6.9316 108.887 0.064 | | | 0

218 4757 48.7149 41.7833 0.421 6.9316 15.463 0.448 | | | 0

219 144 48.7149 41.7833 0.421 6.9316 88.905 0.078 | | | 0

220 3036 48.7149 41.7833 0.421 6.9316 19.358 0.358 | | | 0



Page 17 of 20

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



221 2511 48.7149 41.7833 0.421 6.9316 21.287 0.326 | | | 0

222 961 48.7149 41.7833 0.421 6.9316 34.413 0.201 | | | 0

223 19008 48.7149 41.7833 0.421 6.9316 7.727 0.897 | |* | 0.001

224 547 48.7149 41.7833 0.421 6.9316 45.614 0.152 | | | 0

225 1235 48.7149 41.7833 0.421 6.9316 30.356 0.228 | | | 0

226 4447 48.7149 41.7833 0.421 6.9316 15.993 0.433 | | | 0

227 5335 48.7149 41.7833 0.421 6.9316 14.6 0.475 | | | 0

228 862 48.7149 41.7833 0.421 6.9316 36.336 0.191 | | | 0

229 1204 48.7149 41.7833 0.421 6.9316 30.744 0.225 | | | 0

230 3495 48.7149 41.7833 0.421 6.9316 18.041 0.384 | | | 0

231 4040 48.7149 41.7833 0.421 6.9316 16.78 0.413 | | | 0

232 3882 48.7149 41.7833 0.421 6.9316 17.118 0.405 | | | 0

233 195 48.7149 41.7833 0.421 6.9316 76.399 0.091 | | | 0

234 1071 48.7149 41.7833 0.421 6.9316 32.597 0.213 | | | 0

235 276 48.7149 41.7833 0.421 6.9316 64.217 0.108 | | | 0

236 147 48.7149 41.7833 0.421 6.9316 87.994 0.079 | | | 0

237 1262 48.7149 41.7833 0.421 6.9316 30.029 0.231 | | | 0

238 358 48.7149 41.7833 0.421 6.9316 56.385 0.123 | | | 0

239 3649 48.7149 41.7833 0.421 6.9316 17.656 0.393 | | | 0

240 4834 48.7149 41.7833 0.421 6.9316 15.339 0.452 | | | 0

241 29582 48.7149 41.7833 0.421 6.9316 6.189 1.12 | |** | 0.003

242 1707 48.7149 41.7833 0.421 6.9316 25.819 0.268 | | | 0

243 238 48.7149 41.7833 0.421 6.9316 69.154 0.1 | | | 0

244 1400 48.7149 41.7833 0.421 6.9316 28.51 0.243 | | | 0

245 27181 73.1965 72.9414 0.959 0.2551 6.4 0.04 | | | 0

246 8336 73.1965 72.9414 0.959 0.2551 11.646 0.022 | | | 0

247 320 73.1965 72.9414 0.959 0.2551 59.633 0.004 | | | 0

248 510 73.1965 72.9414 0.959 0.2551 47.232 0.005 | | | 0

249 51749 73.1965 72.9414 0.959 0.2551 4.591 0.056 | | | 0

250 8344 73.1965 72.9414 0.959 0.2551 11.64 0.022 | | | 0

251 18534 73.1965 72.9414 0.959 0.2551 7.778 0.033 | | | 0

252 6807 73.1965 72.9414 0.959 0.2551 12.896 0.02 | | | 0

253 11566 73.1965 72.9414 0.959 0.2551 9.874 0.026 | | | 0

254 14620 73.1965 72.9414 0.959 0.2551 8.771 0.029 | | | 0

255 29978 73.1965 72.9414 0.959 0.2551 6.087 0.042 | | | 0

256 223580 73.1965 72.9414 0.959 0.2551 2.042 0.125 | | | 0.002

257 7490 73.1965 72.9414 0.959 0.2551 12.29 0.021 | | | 0

258 1560 73.1965 72.9414 0.959 0.2551 26.995 0.009 | | | 0

259 18347 73.1965 72.9414 0.959 0.2551 7.818 0.033 | | | 0

260 10470 73.1965 72.9414 0.959 0.2551 10.382 0.025 | | | 0

261 8359 73.1965 72.9414 0.959 0.2551 11.63 0.022 | | | 0

262 9143 73.1965 72.9414 0.959 0.2551 11.116 0.023 | | | 0

263 6786 73.1965 72.9414 0.959 0.2551 12.916 0.02 | | | 0

264 2342 73.1965 72.9414 0.959 0.2551 22.025 0.012 | | | 0

265 8335 73.1965 72.9414 0.959 0.2551 11.646 0.022 | | | 0

266 40416 73.1965 72.9414 0.959 0.2551 5.22 0.049 | | | 0

267 25 73.1965 72.9414 0.959 0.2551 213.373 0.001 | | | 0

268 1514 73.1965 72.9414 0.959 0.2551 27.402 0.009 | | | 0

269 3092 73.1965 72.9414 0.959 0.2551 19.162 0.013 | | | 0

270 4824 73.1965 72.9414 0.959 0.2551 15.331 0.017 | | | 0

271 8166 73.1965 72.9414 0.959 0.2551 11.767 0.022 | | | 0

272 16662 73.1965 72.9414 0.959 0.2551 8.209 0.031 | | | 0

273 4513 73.1965 72.9414 0.959 0.2551 15.852 0.016 | | | 0

274 11204 73.1965 72.9414 0.959 0.2551 10.034 0.025 | | | 0

275 11846 73.1965 72.9414 0.959 0.2551 9.755 0.026 | | | 0

276 2332 73.1965 72.9414 0.959 0.2551 22.072 0.012 | | | 0

277 4682 73.1965 72.9414 0.959 0.2551 15.562 0.016 | | | 0

278 3591 73.1965 72.9414 0.959 0.2551 17.778 0.014 | | | 0

279 12789 73.1965 72.9414 0.959 0.2551 9.385 0.027 | | | 0

280 4556 73.1965 72.9414 0.959 0.2551 15.777 0.016 | | | 0

281 1458 73.1965 72.9414 0.959 0.2551 27.924 0.009 | | | 0

282 403 73.1965 72.9414 0.959 0.2551 53.136 0.005 | | | 0

283 739 73.1965 72.9414 0.959 0.2551 39.234 0.007 | | | 0

284 4346 73.1965 72.9414 0.959 0.2551 16.155 0.016 | | | 0

285 4931 73.1965 72.9414 0.959 0.2551 15.163 0.017 | | | 0

286 21554 73.1965 72.9414 0.959 0.2551 7.203 0.035 | | | 0



Page 18 of 20

‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ MATERIAL=STEEL ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐



287 442 73.1965 72.9414 0.959 0.2551 50.737 0.005 | | | 0

288 1434 73.1965 72.9414 0.959 0.2551 28.157 0.009 | | | 0

289 5965 73.1965 72.9414 0.959 0.2551 13.78 0.019 | | | 0

290 2938 73.1965 72.9414 0.959 0.2551 19.659 0.013 | | | 0

291 5784 73.1965 72.9414 0.959 0.2551 13.995 0.018 | | | 0

292 597 73.1965 72.9414 0.959 0.2551 43.654 0.006 | | | 0

293 296 73.1965 72.9414 0.959 0.2551 62.004 0.004 | | | 0

294 2 73.1965 72.9414 0.959 0.2551 754.395 0 | | | 0

295 727 73.1965 72.9414 0.959 0.2551 39.557 0.006 | | | 0

296 2340 73.1965 72.9414 0.959 0.2551 22.034 0.012 | | | 0

297 2856 73.1965 72.9414 0.959 0.2551 19.94 0.013 | | | 0

298 1191 73.1965 72.9414 0.959 0.2551 30.899 0.008 | | | 0

299 2149 68.2152 116.6 1.926 ‐48.3474 22.933 ‐2.108 | ****| | 0.016

300 163 68.2152 116.6 1.926 ‐48.3474 83.542 ‐0.579 | *| | 0

301 28526 68.2152 116.6 1.926 ‐48.3474 6.016 ‐8.036 |******| | 3.309

302 4031 68.2152 116.6 1.926 ‐48.3474 16.693 ‐2.896 | *****| | 0.056

303 619 68.2152 116.6 1.926 ‐48.3474 42.838 ‐1.129 | **| | 0.001

304 22269 68.2152 116.6 1.926 ‐48.3474 6.885 ‐7.022 |******| | 1.929

305 21 68.2152 116.6 1.926 ‐48.3474 232.804 ‐0.208 | | | 0

306 545 68.2152 116.6 1.926 ‐48.3474 45.659 ‐1.059 | **| | 0.001

307 385 68.2152 116.6 1.926 ‐48.3474 54.339 ‐0.89 | *| | 0

308 18 68.2152 116.6 1.926 ‐48.3474 251.458 ‐0.192 | | | 0

309 1879 68.2152 116.6 1.926 ‐48.3474 24.537 ‐1.970 | ***| | 0.012

310 896 68.2152 116.6 1.926 ‐48.3474 35.59 ‐1.358 | **| | 0.003

311 509 68.2152 116.6 1.926 ‐48.3474 47.249 ‐1.023 | **| | 0.001

312 311 68.2152 116.6 1.926 ‐48.3474 60.466 ‐0.8 | *| | 0

313 1111 68.2152 116.6 1.926 ‐48.3474 31.95 ‐1.513 | ***| | 0.004

314 2511 68.2152 116.6 1.926 ‐48.3474 21.203 ‐2.28 | ****| | 0.021

315 2471 68.2152 116.6 1.926 ‐48.3474 21.376 ‐2.262 | ****| | 0.021

316 964 68.2152 116.6 1.926 ‐48.3474 34.308 ‐1.409 | **| | 0.003

317 380 68.2152 116.6 1.926 ‐48.3474 54.696 ‐0.884 | *| | 0

318 2774 68.2152 116.6 1.926 ‐48.3474 20.165 ‐2.398 | ****| | 0.026

319 9 68.2152 116.6 1.926 ‐48.3474 355.62 ‐0.136 | | | 0

320 11 39.3868 172.6 3.209 ‐133.3 321.66 ‐0.414 | | | 0

321 150 39.3868 172.6 3.209 ‐133.3 87.051 ‐1.531 | ***| | 0.002

SUM OF RESIDUALS 0






Page 19 of 20




MATERIAL _MODEL_ _TYPE_ _DEPVAR_ _RMSE_ INTERCEP SQSIZE UHWICOST

PLASTIC MODEL1 PARMS UHWICOST 180.29 10.3209 0.7452 ‐1

STEEL MODEL1 PARMS UHWICOST 1,066.88 16.8568 1.5579 ‐1

MINIMUM MINIMUM

SYSTEM SYSTEM AT

CURRENT COST CURRENT

MATERIAL QUANTITY PER UNIT COST

PLASTIC 10,587,131 10.3209 109,269,168

STEEL 7,381,860 16.8568 124,434,736

17,968,991 233,703,904

MINIMUM MINIMUM DEMAND

SYSTEM AT TOTAL AT SYSTEM AT RELATED

CURRENT CURRENT CURRENT COST CURRENT COST

COST COST PERCENT PERCENT

233,703,904 431,644,983 0.54143 0.45857


Current Cost Estimates


Estimation of Minimum Cost of Gas Mains


Estimation of Percentage of Minimum Cost of Gas Mains



Page 20 of 20

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Page 1 of 4

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Page 2 of 4

Mic

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mis

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as U

tiliti

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Page 2 of 20

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G IN

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Acc

t 487

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te P

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n R

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6,00

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2,84

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208

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t 488

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t 494

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08

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t 495

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cella

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: M

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965)

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2)(8

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May

not

cro

ss-c

heck

due

to R

ound

ing



Page 3 of 20

Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

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t of S

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tion

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OC

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t 487

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08

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9

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17

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due

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ound

ing



Page 4 of 20

Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

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t of S

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lloca

tion

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ATI

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Page 5 of 20

Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

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ratio

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Page 6 of 20

Mic

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n P

ublic

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vice

Com

mis

sion

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higa

n G

as U

tiliti

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ratio

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Page 7 of 20

Mic

higa

n P

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Com

mis

sion

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higa

n G

as U

tiliti

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ratio

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Page 8 of 20

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Wei

ghte

d P

eak

Dem

and

4,80

2,09

92,

059,

604

3,29

817

,128

4,08

07,

325

442,

109

39,5

6825

4,69

651

7,53

138

6,78

621

379

Wei

ghte

d P

eak

Dem

and

(37,

850)

(16,

234)

(26)

(135

)(3

2)(5

8)(3

,485

)(3

12)

(2,0

07)

(4,0

79)

(3,0

49)

2238

0S

ervi

ces

70,7

38,3

8754

,944

,294

51,4

6180

,635

5,72

84,

482

3,23

3,33

311

,356

60,7

0520

,870

3,26

723

381

Met

ers

36,6

26,0

5220

,125

,379

12,2

5592

,560

22,9

379,

375

8,13

7,87

829

,199

153,

312

52,3

546,

413

2438

2M

eter

s0

00

00

00

00

00

2538

3C

usto

mer

15,1

48,3

1311

,714

,399

10,9

7218

,220

1,29

41,

013

730,

601

2,56

610

,188

3,50

254

826

385

Acc

t 385

Dem

and

620,

356

00

00

00

20,4

1913

1,43

726

7,07

519

9,60

327

T

otal

Dis

tribu

tion

250,

228,

894

163,

932,

680

164,

438

489,

359

87,7

1311

2,87

820

,921

,769

580,

328

3,65

4,72

56,

972,

781

5,15

5,13

928 29

C

usto

mer

Cus

tom

er0

00

00

00

00

00

30 31To

tal P

lant

in S

ervi

ce31

0,26

2,59

118

8,94

5,15

320

3,61

270

3,71

414

0,10

920

5,55

626

,579

,722

1,34

9,92

16,

827,

573

13,3

94,9

9010

,544

,328

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nH

isto

rical

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyH

isto

rical

Yea

r End

ing

Dec

embe

r 31,

201

2

ALL

OC

ATI

ON

OF

RA

TE B

AS

E C

OM

PO

NE

NT

- PLA

NT

IN S

ER

VIC

E(A

)(B

)(C

)

LIN

E

NO

.D

ES

CR

IPTI

ON

ALL

OC

ATI

ON

FA

CTO

RC

OR

PO

RA

TE

TOTA

L1

GA

S P

LAN

T:2

P

rodu

ctio

n:3

P

urch

ased

Gas

Cos

tS

ales

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d2,

416,

670

5

Sto

rage

Cos

tS

tora

ge15

,799

,487

6

Tot

al P

rodu

ctio

n18

,216

,157

7 8

Tra

nsm

issi

on9

M

inim

um S

yste

m -

Thro

ughp

ut P

iece

MC

F Th

roug

hput

19,1

50,5

7910

D

eman

d R

elat

ed S

yste

mW

eigh

ted

Pea

k D

eman

d22

,666

,961

11

Tot

al T

rans

mis

sion

41,8

17,5

4012 13

D

istri

butio

n14

302/

303

Wei

ghte

d P

eak

Dem

and

232,

474

1537

4W

eigh

ted

Pea

k D

eman

d34

2,71

716

375

Wei

ghte

d P

eak

Dem

and

359,

508

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d55

,669

,409

1837

6 (F

ixed

Cos

t)C

usto

mer

65,7

27,4

2719

377

MC

F Th

roug

hput

020

378

Wei

ghte

d P

eak

Dem

and

4,80

2,09

921

379

Wei

ghte

d P

eak

Dem

and

(37,

850)

2238

0S

ervi

ces

70,7

38,3

8723

381

Met

ers

36,6

26,0

5224

382

Met

ers

025

383

Cus

tom

er15

,148

,313

2638

5A

cct 3

85 D

eman

d62

0,35

627

T

otal

Dis

tribu

tion

250,

228,

894

28 29

Cus

tom

erC

usto

mer

030 31

Tota

l Pla

nt in

Ser

vice

310,

262,

591

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)(O

)

Cus

tom

er C

hoic

e -

Res

iden

tial

Cus

tom

er C

hoic

e -

Sm

all G

SC

usto

mer

Cho

ice

- La

rge

GS

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IC

usto

mer

Cho

ice

- M

ulti-

Fam

ily II

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

III

Cus

tom

er C

hoic

e -

Mul

ti-Fa

mily

IVA

gg T

rans

port

- R

esid

entia

lA

gg T

rans

port

- S

mal

l GS

Agg

Tra

nspo

rt -

Larg

e G

SS

peci

al C

ontra

ct

00

00

00

00

00

021

7,86

222

9,52

40

164

422

201

761

687

87,0

701,

759

171,

510,

188

1,70

2,24

90

1,26

23,

355

2,59

58,

824

4,99

661

2,21

423

,027

569

1,72

8,05

01,

931,

773

01,

427

3,77

82,

796

9,58

65,

683

699,

284

24,7

8658

6

1,43

0,65

61,

658,

179

01,

080

3,05

11,

452

5,50

04,

512

629,

030

18,9

2818

42,

043,

417

2,15

2,79

80

1,54

23,

962

1,88

67,

140

6,44

581

6,66

416

,497

161

3,47

4,07

43,

810,

976

02,

621

7,01

33,

338

12,6

4010

,957

1,44

5,69

435

,425

345

20,9

5722

,079

016

4119

7366

8,37

616

92

30,8

9632

,550

023

6029

108

9712

,348

249

232

,410

34,1

440

2463

3011

310

212

,953

262

35,

018,

575

5,28

7,21

00

3,78

79,

730

4,63

117

,536

15,8

282,

005,

703

40,5

1739

59,

361,

282

1,94

1,95

70

4,52

64,

823

396

396

13,8

0919

1,15

01,

156

396

00

00

00

00

00

043

2,90

745

6,08

00

327

839

399

1,51

31,

365

173,

014

3,49

534

(3,4

12)

(3,5

95)

0(3

)(7

)(3

)(1

2)(1

1)(1

,364

)(2

8)(0

)10

,119

,419

1,98

0,73

90

4,89

34,

920

404

404

14,9

2819

4,96

71,

179

404

2,83

5,33

44,

786,

473

068

23,

130

2,15

578

34,

425

348,

129

2,39

488

50

00

00

00

00

00

2,15

7,51

144

7,56

60

1,04

31,

112

9191

3,18

344

,055

266

910

00

00

00

00

1,80

418

30,0

05,8

7914

,985

,203

015

,318

24,7

118,

152

21,0

0653

,792

2,98

9,32

951

,464

2,23

0

00

00

00

00

00

0

35,2

08,0

0220

,727

,952

019

,367

35,5

0114

,285

43,2

3270

,431

5,13

4,30

611

1,67

53,

161

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nH

isto

rical

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyH

isto

rical

Yea

r End

ing

Dec

embe

r 31,

201

2

ALL

OC

ATI

ON

OF

RA

TE B

AS

E C

OM

PO

NE

NT

- DE

PR

EC

IATI

ON

RE

SE

RV

E -

S/L

(A)

(B)

(C)

(D)

(E)

(F)

(G)

(H)

(I)(J

)(K

)(L

)(N

)

LIN

E

NO

.D

ES

CR

IPTI

ON

ALL

OC

ATI

ON

FA

CTO

RC

OR

PO

RA

TE

TOTA

LR

esid

entia

lM

ulti-

Fam

ily -

Cla

ss I

Mul

ti-Fa

mily

- C

lass

IIM

ulti-

Fam

ily -

Cla

ss

IIIM

ulti-

Fam

ily -

Cla

ss

IVS

mal

l Gen

eral

S

ervi

ceLa

rge

Gen

eral

S

ervi

ceTr

ansp

ort -

TR

-1Tr

ansp

ort -

TR

-2Tr

ansp

ort -

TR

-31

DE

PR

EC

IATI

ON

RE

SE

RV

E -

S/L

:2

P

rodu

ctio

n:3

P

urch

ased

Gas

Cos

tS

ales

00

00

00

00

00

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d(1

,238

,072

)(5

31,0

05)

(850

)(4

,416

)(1

,052

)(1

,889

)(1

13,9

84)

(10,

201)

(65,

665)

(133

,429

)(9

9,72

1)5

S

tora

ge C

ost

Sto

rage

(7,4

42,1

08)

(3,5

08,1

17)

(5,2

05)

(29,

494)

(7,6

55)

(13,

086)

(820

,176

)(1

64,2

14)

(258

,195

)(4

31,5

07)

(381

,893

)6

T

otal

Pro

duct

ion

(8,6

80,1

80)

(4,0

39,1

22)

(6,0

55)

(33,

910)

(8,7

07)

(14,

975)

(934

,160

)(1

74,4

15)

(323

,861

)(5

64,9

36)

(481

,614

)7 8

T

rans

mis

sion

9

Min

imum

Sys

tem

- Th

roug

hput

Pie

ceM

CF

Thro

ughp

ut(1

2,75

3,07

5)(4

,532

,702

)(7

,258

)(4

1,46

9)(9

,878

)(1

7,73

6)(1

,070

,417

)(1

42,7

03)

(861

,927

)(1

,866

,499

)(1

,703

,511

)10

D

eman

d R

elat

ed S

yste

mW

eigh

ted

Pea

k D

eman

d(1

5,02

0,30

8)(6

,442

,160

)(1

0,31

5)(5

3,57

4)(1

2,76

1)(2

2,91

3)(1

,382

,858

)(1

23,7

62)

(796

,653

)(1

,618

,766

)(1

,209

,814

)11

T

otal

Tra

nsm

issi

on(2

7,77

3,38

3)(1

0,97

4,86

2)(1

7,57

3)(9

5,04

3)(2

2,63

9)(4

0,64

9)(2

,453

,274

)(2

66,4

65)

(1,6

58,5

80)

(3,4

85,2

65)

(2,9

13,3

25)

12 13

Dis

tribu

tion

1430

2/30

3W

eigh

ted

Pea

k D

eman

d(2

19,0

37)

(93,

944)

(150

)(7

81)

(186

)(3

34)

(20,

166)

(1,8

05)

(11,

617)

(23,

606)

(17,

642)

1537

4W

eigh

ted

Pea

k D

eman

d(2

6,19

8)(1

1,23

6)(1

8)(9

3)(2

2)(4

0)(2

,412

)(2

16)

(1,3

89)

(2,8

23)

(2,1

10)

1637

5W

eigh

ted

Pea

k D

eman

d(2

31,2

29)

(99,

174)

(159

)(8

25)

(196

)(3

53)

(21,

288)

(1,9

05)

(12,

264)

(24,

920)

(18,

624)

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d(3

1,70

8,70

3)(1

3,59

9,75

7)(2

1,77

6)(1

13,0

97)

(26,

939)

(48,

370)

(2,9

19,2

89)

(261

,269

)(1

,681

,779

)(3

,417

,306

)(2

,553

,985

)18

376

(Fix

ed C

ost)

Cus

tom

er(3

7,43

7,64

3)(2

8,95

1,04

4)(2

7,11

6)(4

5,03

0)(3

,199

)(2

,503

)(1

,805

,613

)(6

,341

)(2

5,17

8)(8

,656

)(1

,355

)19

377

MC

F Th

roug

hput

00

00

00

00

00

020

378

Wei

ghte

d P

eak

Dem

and

(3,1

08,6

35)

(1,3

33,2

83)

(2,1

35)

(11,

088)

(2,6

41)

(4,7

42)

(286

,199

)(2

5,61

4)(1

64,8

77)

(335

,023

)(2

50,3

86)

2137

9W

eigh

ted

Pea

k D

eman

d(2

81)

(120

)(0

)(1

)(0

)(0

)(2

6)(2

)(1

5)(3

0)(2

3)22

380

Ser

vice

s(3

9,64

8,46

4)(3

0,79

5,96

4)(2

8,84

4)(4

5,19

6)(3

,211

)(2

,512

)(1

,812

,265

)(6

,365

)(3

4,02

5)(1

1,69

8)(1

,831

)23

381

Met

ers

(16,

839,

055)

(9,2

52,7

68)

(5,6

34)

(42,

555)

(10,

545)

(4,3

10)

(3,7

41,4

40)

(13,

424)

(70,

486)

(24,

070)

(2,9

49)

2438

2M

eter

s0

00

00

00

00

00

2538

3C

usto

mer

(5,6

33,5

27)

(4,3

56,4

84)

(4,0

80)

(6,7

76)

(481

)(3

77)

(271

,704

)(9

54)

(3,7

89)

(1,3

03)

(204

)26

385

Acc

t 385

Dem

and

(334

,036

)0

00

00

0(1

0,99

5)(7

0,77

4)(1

43,8

09)

(107

,478

)27

T

otal

Dis

tribu

tion

(135

,186

,807

)(8

8,49

3,77

5)(8

9,91

2)(2

65,4

42)

(47,

421)

(63,

541)

(10,

880,

402)

(328

,891

)(2

,076

,193

)(3

,993

,244

)(2

,956

,587

)28 29

C

usto

mer

Cus

tom

er0

00

00

00

00

00

30 31To

tal D

epre

ciat

ion

Res

erve

- S

traig

ht L

ine:

(171

,640

,370

)(1

03,5

07,7

60)

(113

,540

)(3

94,3

95)

(78,

767)

(119

,164

)(1

4,26

7,83

7)(7

69,7

71)

(4,0

58,6

34)

(8,0

43,4

45)

(6,3

51,5

26)

May

not

cro

ss-c

heck

due

to R

ound

ing



Mic

higa

n P

ublic

Ser

vice

Com

mis

sion

Mic

higa

n G

as U

tiliti

es C

orpo

ratio

nH

isto

rical

Cos

t of S

ervi

ce A

lloca

tion

Stu

dyH

isto

rical

Yea

r End

ing

Dec

embe

r 31,

201

2

ALL

OC

ATI

ON

OF

RA

TE B

AS

E C

OM

PO

NE

NT

- DE

PR

EC

IATI

ON

RE

SE

RV

E -

S/L

(A)

(B)

(C)

LIN

E

NO

.D

ES

CR

IPTI

ON

ALL

OC

ATI

ON

FA

CTO

RC

OR

PO

RA

TE

TOTA

L1

DE

PR

EC

IATI

ON

RE

SE

RV

E -

S/L

:2

P

rodu

ctio

n:3

P

urch

ased

Gas

Cos

tS

ales

04

P

rodu

ctio

n D

eman

dW

eigh

ted

Pea

k D

eman

d(1

,238

,072

)5

S

tora

ge C

ost

Sto

rage

(7,4

42,1

08)

6

Tot

al P

rodu

ctio

n(8

,680

,180

)7 8

T

rans

mis

sion

9

Min

imum

Sys

tem

- Th

roug

hput

Pie

ceM

CF

Thro

ughp

ut(1

2,75

3,07

5)10

D

eman

d R

elat

ed S

yste

mW

eigh

ted

Pea

k D

eman

d(1

5,02

0,30

8)11

T

otal

Tra

nsm

issi

on(2

7,77

3,38

3)12 13

D

istri

butio

n14

302/

303

Wei

ghte

d P

eak

Dem

and

(219

,037

)15

374

Wei

ghte

d P

eak

Dem

and

(26,

198)

1637

5W

eigh

ted

Pea

k D

eman

d(2

31,2

29)

1737

6 (D

eman

d)W

eigh

ted

Pea

k D

eman

d(3

1,70

8,70

3)18

376

(Fix

ed C

ost)

Cus

tom

er(3

7,43

7,64

3)19

377

MC

F Th

roug

hput

020

378

Wei

ghte

d P

eak

Dem

and

(3,1

08,6

35)

2137

9W

eigh

ted

Pea

k D

eman

d(2

81)

2238

0S

ervi

ces

(39,

648,

464)

2338

1M

eter

s(1

6,83

9,05

5)24

382

Met

ers

025

383

Cus

tom

er(5

,633

,527

)26

385

Acc

t 385

Dem

and

(334

,036

)27

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Michigan Public Service CommissionMichigan Gas Utilities CorporationHistorical Cost of Service Allocation StudyHistorical Year Ending December 31, 2012Revenue Requirement and Rate Base by Individual Rate Schedule

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: RESIDENTIAL GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 49,461,802 49,461,802 5 Gas Supply Acquisition Cost 562,095 562,095 6 Production Demand 161,635 161,635 7 Storage Cost 235,977 235,977 8 Total - Production 49,461,802 562,095 161,635 235,977 - - - - 50,421,509 910 Transmission: 129,325 11,494 140,819 11 Distribution: 802,483 4,681,859 5,484,343 12 Customer Accounts and Services: - 13 Allocable 6,973,238 6,973,238 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 432,805 124,456 118,503 800,486 - 6,977,249 - 8,453,499 17 Total Operation & Maintenance Expense: 49,461,802 994,900 286,091 354,480 1,732,295 4,693,353 13,950,486 - 71,473,408 1819 Depreciation & Amort Expense: - - 24,396 160,773 928,594 4,062,305 - - 5,176,068 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1,229 641 556 1,809 15,650 8,537 - 28,422 23 Retirement Benefits - FED 14,698 7,672 6,646 21,642 187,244 102,138 - 340,040 24 IBS Payroll Tax 8,146 4,252 3,684 11,995 103,778 56,609 - 188,464 25 Michigan SBT & Real Estate/Property - - 12,155 212,500 477,513 1,120,884 - - 1,823,053 26 Misc - Unauthorized Ins. Tax & Franchise - - 53 930 2,089 4,904 - - 7,976 27 Total Taxes Other Than Income Taxes: - 24,073 24,773 224,316 515,048 1,432,460 167,284 - 2,387,955 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 11,634 203,397 457,058 1,072,868 - - 1,744,957 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 49,461,802 1,018,973 346,895 942,966 3,632,995 11,260,987 14,117,771 - 80,782,388 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (1,515) (26,492) (59,530) (139,738) - - (227,276) 40 Acct 488, Acct 495: Miscellaneous (230,060) (230,060) 41 Acct 495: Customer Penalities & Gas True-up (4,569,982) (4,569,982) 42 Acct 495: VBA and Decoupling related (470,051) (470,051) 43 Total Other Operating Income: (4,569,982) - (1,515) (26,492) (529,581) (139,738) (230,060) - (5,497,369) 4445 Actual Return (Net Operating Income) - - (9,486) (165,837) (372,656) (874,749) - - (1,422,729) 4647 Return Income Deficiency - - 61,973 1,083,449 2,434,640 5,714,915 - - 9,294,976 4849 Additional Income Taxes on Deficiency: - - 9,300 162,586 365,350 857,598 - - 1,394,834 5051 REVENUE REQUIREMENTS: 44,891,820 1,018,973 407,166 1,996,672 5,530,746 16,819,012 13,887,710 - 84,552,100 5253545556 RATE BASE:57 Utility Plant in Service - - 1,036,502 7,447,682 36,042,469 144,418,500 - - 188,945,153 58 Accumulated Depreciation - S/L - - (531,005) (3,508,117) (21,579,675) (77,888,963) - - (103,507,760) 59 Construction Work in Progress - - 19,024 235,570 856,248 1,065,762 - - 2,176,604 60 Net Plant in Service - - 524,520 4,175,135 15,319,042 67,595,300 - - 87,613,997 6162 Gas Stored Underground: - - - 7,800,379 - - - - 7,800,379 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 113,226 911,490 13,893,905 - - - 14,918,622 65 Materials & Supplies: - - - - 60,689 268,070 - - 328,759 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 8,968 9,282 184,637 - - - 202,888 68 Cash & Bank Balances - - 96,304 11,595 174,832 - - - 282,731 69 Property, Payroll & Income Taxes Accrued: - - (7,106) (42,155) (722,290) - - (771,551) 70 TOTAL RATE BASE - - 735,912 12,865,726 28,910,816 67,863,370 - - 110,375,824 71 % of Rate Base 0.0000% 0.0000% 0.6667% 11.6563% 26.1931% 61.4839% 0.0000% 0.0000% 100.0000%





Page 1 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY I GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 79,197 79,197 5 Gas Supply Acquisition Cost 900 900 6 Production Demand 259 259 7 Storage Cost 350 350 8 Total - Production 79,197 900 259 350 - - - - 80,706 910 Transmission: 207 18 225 11 Distribution: 1,285 4,027 5,312 12 Customer Accounts and Services: - 13 Allocable 6,630 6,630 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 693 199 176 1,282 - 6,633 - 8,983 17 Total Operation & Maintenance Expense: 79,197 1,593 458 526 2,774 4,046 13,263 - 101,857 1819 Depreciation & Amort Expense: - - 39 239 1,487 3,745 - - 5,509 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 2 1 1 2 20 11 - 37 23 Retirement Benefits - FED 19 10 9 28 245 134 - 445 24 IBS Payroll Tax 11 6 5 16 136 74 - 247 25 Michigan SBT & Real Estate/Property - - 19 315 718 1,017 - - 2,070 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 1 3 4 - - 9 27 Total Taxes Other Than Income Taxes: - 32 36 331 767 1,423 219 - 2,808 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 19 302 687 974 - - 1,981 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 79,197 1,625 552 1,397 5,715 10,187 13,482 - 112,155 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (2) (36) (82) (116) - - (236) 40 Acct 488, Acct 495: Miscellaneous (149) (149) 41 Acct 495: Customer Penalities & Gas True-up (7,317) (7,317) 42 Acct 495: VBA and Decoupling related 790 790 43 Total Other Operating Income: (7,317) - (2) (36) 708 (116) (149) - (6,912) 4445 Actual Return (Net Operating Income) - - (7) (119) (272) (385) - - (783) 4647 Return Income Deficiency - - 91 1,481 3,370 4,778 - - 9,720 4849 Additional Income Taxes on Deficiency: - - 15 241 549 778 - - 1,583 5051 REVENUE REQUIREMENTS: 71,880 1,625 648 2,964 10,071 15,242 13,333 - 115,763 5253545556 RATE BASE:57 Utility Plant in Service - - 1,660 11,049 57,711 133,192 - - 203,612 58 Accumulated Depreciation - S/L - - (850) (5,205) (34,553) (72,932) - - (113,540) 59 Construction Work in Progress - - 30 349 1,371 1,076 - - 2,827 60 Net Plant in Service - - 840 6,194 24,529 61,337 - - 92,899 6162 Gas Stored Underground: - - - 11,573 - - - - 11,573 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 181 1,352 19,404 - - - 20,937 65 Materials & Supplies: - - - - 97 251 - - 348 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 14 14 296 - - - 323 68 Cash & Bank Balances - - 154 17 280 - - - 451 69 Property, Payroll & Income Taxes Accrued: - - (11) (63) (1,157) - - (1,230) 70 TOTAL RATE BASE - - 1,178 19,088 43,448 61,588 - - 125,302 71 % of Rate Base 0.0000% 0.0000% 0.9400% 15.2336% 34.6748% 49.1516% 0.0000% 0.0000% 100.0000%





Page 2 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY II GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 452,523 452,523 5 Gas Supply Acquisition Cost 5,143 5,143 6 Production Demand 1,344 1,344 7 Storage Cost 1,984 1,984 8 Total - Production 452,523 5,143 1,344 1,984 - - - - 460,994 910 Transmission: 1,075 105 1,181 11 Distribution: 6,674 10,472 17,146 12 Customer Accounts and Services: - 13 Allocable 14,705 14,705 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 3,960 1,035 996 6,657 - 14,713 - 27,361 17 Total Operation & Maintenance Expense: 452,523 9,102 2,379 2,980 14,406 10,578 29,418 - 521,386 1819 Depreciation & Amort Expense: - - 203 1,352 7,722 7,757 - - 17,034 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 7 3 3 10 84 46 - 153 23 Retirement Benefits - FED 79 41 36 116 1,006 549 - 1,827 24 IBS Payroll Tax 44 23 20 64 558 304 - 1,012 25 Michigan SBT & Real Estate/Property - - 103 1,787 3,847 2,558 - - 8,294 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 8 17 11 - - 36 27 Total Taxes Other Than Income Taxes: - 129 171 1,853 4,054 4,217 899 - 11,323 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 98 1,710 3,682 2,449 - - 7,939 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 452,523 9,232 2,851 7,895 29,864 25,001 30,316 - 557,682 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (15) (265) (570) (379) - - (1,229) 40 Acct 488, Acct 495: Miscellaneous 526 526 41 Acct 495: Customer Penalities & Gas True-up (41,811) (41,811) 42 Acct 495: VBA and Decoupling related 4,449 4,449 43 Total Other Operating Income: (41,811) - (15) (265) 3,879 (379) 526 - (38,064) 4445 Actual Return (Net Operating Income) - - 807 14,047 30,245 20,116 - - 65,214 4647 Return Income Deficiency - - (364) (6,332) (13,634) (9,068) - - (29,398) 4849 Additional Income Taxes on Deficiency: - - 79 1,367 2,943 1,957 - - 6,346 5051 REVENUE REQUIREMENTS: 410,713 9,232 3,358 16,712 53,297 37,627 30,843 - 561,780 5253545556 RATE BASE:57 Utility Plant in Service - - 8,620 62,616 299,734 332,745 - - 703,714 58 Accumulated Depreciation - S/L - - (4,416) (29,494) (179,459) (181,026) - - (394,395) 59 Construction Work in Progress - - 158 1,981 7,121 2,761 - - 12,021 60 Net Plant in Service - - 4,362 35,102 127,395 154,480 - - 321,339 6162 Gas Stored Underground: - - - 65,581 - - - - 65,581 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 1,036 7,663 107,981 - - - 116,681 65 Materials & Supplies: - - - - 505 417 - - 922 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 75 78 1,536 - - - 1,689 68 Cash & Bank Balances - - 801 97 1,468 - - - 2,366 69 Property, Payroll & Income Taxes Accrued: - - (59) (354) (5,989) - - (6,403) 70 TOTAL RATE BASE - - 6,215 108,167 232,895 154,897 - - 502,175 71 % of Rate Base 0.0000% 0.0000% 1.2376% 21.5398% 46.3773% 30.8453% 0.0000% 0.0000% 100.0000%





Page 3 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY III GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 107,788 107,788 5 Gas Supply Acquisition Cost 1,225 1,225 6 Production Demand 320 320 7 Storage Cost 515 515 8 Total - Production 107,788 1,225 320 515 - - - - 109,848 910 Transmission: 256 25 281 11 Distribution: 1,590 1,632 3,221 12 Customer Accounts and Services: - 13 Allocable 1,400 1,400 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 943 247 259 1,586 - 1,401 - 4,434 17 Total Operation & Maintenance Expense: 107,788 2,168 567 774 3,431 1,657 2,800 - 119,184 1819 Depreciation & Amort Expense: - - 48 351 1,839 940 - - 3,178 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 1 1 2 18 10 - 33 23 Retirement Benefits - FED 17 9 8 25 219 119 - 398 24 IBS Payroll Tax 10 5 4 14 121 66 - 220 25 Michigan SBT & Real Estate/Property - - 24 464 988 389 - - 1,865 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 2 4 2 - - 8 27 Total Taxes Other Than Income Taxes: - 28 39 478 1,034 749 196 - 2,525 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 23 444 946 372 - - 1,785 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 107,788 2,196 678 2,047 7,250 3,718 2,996 - 126,673 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (2) (42) (90) (35) - - (170) 40 Acct 488, Acct 495: Miscellaneous 242 242 41 Acct 495: Customer Penalities & Gas True-up (9,959) (9,959) 42 Acct 495: VBA and Decoupling related (8,775) (8,775) 43 Total Other Operating Income: (9,959) - (2) (42) (8,865) (35) 242 - (18,662) 4445 Actual Return (Net Operating Income) - - 234 4,440 9,460 3,725 - - 17,859 4647 Return Income Deficiency - - (129) (2,438) (5,194) (2,045) - - (9,805) 4849 Additional Income Taxes on Deficiency: - - 19 355 756 298 - - 1,427 5051 REVENUE REQUIREMENTS: 97,829 2,196 800 4,362 3,407 5,660 3,238 - 117,492 5253545556 RATE BASE:57 Utility Plant in Service - - 2,053 16,252 71,394 50,409 - - 140,109 58 Accumulated Depreciation - S/L - - (1,052) (7,655) (42,746) (27,314) - - (78,767) 59 Construction Work in Progress - - 38 514 1,696 427 - - 2,675 60 Net Plant in Service - - 1,039 9,111 30,345 23,521 - - 64,016 6162 Gas Stored Underground: - - - 17,022 - - - - 17,022 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 247 1,989 30,065 - - - 32,301 65 Materials & Supplies: - - - - 120 30 - - 150 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 18 20 366 - - - 404 68 Cash & Bank Balances - - 191 25 350 - - - 566 69 Property, Payroll & Income Taxes Accrued: - - (14) (92) (1,427) - - (1,533) 70 TOTAL RATE BASE - - 1,481 28,076 59,818 23,551 - - 112,926 71 % of Rate Base 0.0000% 0.0000% 1.3115% 24.8620% 52.9709% 20.8556% 0.0000% 0.0000% 100.0000%





Page 4 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: MULTI-FAMILY IV GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 193,537 193,537 5 Gas Supply Acquisition Cost 2,199 2,199 6 Production Demand 575 575 7 Storage Cost 880 880 8 Total - Production 193,537 2,199 575 880 - - - - 197,192 910 Transmission: 460 45 505 11 Distribution: 2,854 812 3,666 12 Customer Accounts and Services: - 13 Allocable 1,494 1,494 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 1,694 443 442 2,847 - 1,495 - 6,920 17 Total Operation & Maintenance Expense: 193,537 3,893 1,018 1,322 6,161 857 2,989 - 209,776 1819 Depreciation & Amort Expense: - - 87 600 3,303 758 - - 4,748 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 3 1 1 4 32 17 - 58 23 Retirement Benefits - FED 30 16 14 44 383 209 - 696 24 IBS Payroll Tax 17 9 8 25 213 116 - 386 25 Michigan SBT & Real Estate/Property - - 44 793 1,699 315 - - 2,851 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 3 7 1 - - 12 27 Total Taxes Other Than Income Taxes: - 49 70 818 1,779 945 343 - 4,004 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 42 759 1,626 302 - - 2,729 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 193,537 3,942 1,216 3,499 12,869 2,862 3,331 - 221,257 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (3) (63) (134) (25) - - (225) 40 Acct 488, Acct 495: Miscellaneous 117 117 41 Acct 495: Customer Penalities & Gas True-up (17,882) (17,882) 42 Acct 495: VBA and Decoupling related (15,623) (15,623) 43 Total Other Operating Income: (17,882) - (3) (63) (15,757) (25) 117 - (33,613) 4445 Actual Return (Net Operating Income) - - 459 8,284 17,754 3,296 - - 29,792 4647 Return Income Deficiency - - (269) (4,861) (10,418) (1,934) - - (17,482) 4849 Additional Income Taxes on Deficiency: - - 34 606 1,300 241 - - 2,181 5051 REVENUE REQUIREMENTS: 175,656 3,942 1,436 7,466 5,748 4,440 3,449 - 202,136 5253545556 RATE BASE:57 Utility Plant in Service - - 3,687 27,781 128,192 45,896 - - 205,556 58 Accumulated Depreciation - S/L - - (1,889) (13,086) (76,752) (27,437) - - (119,164) 59 Construction Work in Progress - - 68 879 3,045 615 - - 4,606 60 Net Plant in Service - - 1,866 15,574 54,485 19,074 - - 90,998 6162 Gas Stored Underground: - - - 29,097 - - - - 29,097 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 443 3,400 49,434 - - - 53,277 65 Materials & Supplies: - - - - 216 23 - - 239 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 32 35 657 - - - 723 68 Cash & Bank Balances - - 343 43 628 - - - 1,014 69 Property, Payroll & Income Taxes Accrued: - - (25) (157) (2,562) - - (2,744) 70 TOTAL RATE BASE - - 2,659 47,992 102,858 19,097 - - 172,605 71 % of Rate Base 0.0000% 0.0000% 1.5403% 27.8044% 59.5916% 11.0637% 0.0000% 0.0000% 100.0000%





Page 5 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: SMALL GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 11,680,616 11,680,616 5 Gas Supply Acquisition Cost 132,741 132,741 6 Production Demand 34,696 34,696 7 Storage Cost 55,170 55,170 8 Total - Production 11,680,616 132,741 34,696 55,170 - - - - 11,903,223 910 Transmission: 27,761 2,714 30,475 11 Distribution: 172,259 660,079 832,338 12 Customer Accounts and Services: - 13 Allocable 561,328 561,328 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 102,209 26,715 27,705 171,830 - 561,651 - 890,111 17 Total Operation & Maintenance Expense: 11,680,616 234,950 61,412 82,875 371,850 662,793 1,122,979 - 14,217,475 1819 Depreciation & Amort Expense: - - 5,237 37,588 199,330 375,204 - - 617,358 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 183 95 83 269 2,326 1,269 - 4,225 23 Retirement Benefits - FED 2,185 1,140 988 3,217 27,832 15,182 - 50,545 24 IBS Payroll Tax 1,211 632 548 1,783 15,426 8,415 - 28,014 25 Michigan SBT & Real Estate/Property - - 2,649 49,681 105,993 137,005 - - 295,329 26 Misc - Unauthorized Ins. Tax & Franchise - - 12 217 464 599 - - 1,292 27 Total Taxes Other Than Income Taxes: - 3,578 4,529 51,517 111,725 183,190 24,866 - 379,404 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2,536 47,553 101,452 131,136 - - 282,678 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 11,680,616 238,528 73,713 219,533 784,357 1,352,323 1,147,845 - 15,496,914 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (384) (7,208) (15,379) (19,879) - - (42,851) 40 Acct 488, Acct 495: Miscellaneous 32,813 32,813 41 Acct 495: Customer Penalities & Gas True-up (1,079,221) (1,079,221) 42 Acct 495: VBA and Decoupling related 92,671 92,671 43 Total Other Operating Income: (1,079,221) - (384) (7,208) 77,292 (19,879) 32,813 - (996,588) 4445 Actual Return (Net Operating Income) - - 16,090 301,730 643,728 832,079 - - 1,793,628 4647 Return Income Deficiency - - (4,650) (87,198) (186,034) (240,466) - - (518,349) 4849 Additional Income Taxes on Deficiency: - - 2,027 38,012 81,096 104,824 - - 225,959 5051 REVENUE REQUIREMENTS: 10,601,395 238,528 86,796 464,868 1,400,439 2,028,881 1,180,657 - 16,001,564 5253545556 RATE BASE:57 Utility Plant in Service - - 222,493 1,741,222 7,736,784 16,879,224 - - 26,579,722 58 Accumulated Depreciation - S/L - - (113,984) (820,176) (4,632,237) (8,701,439) - - (14,267,837) 59 Construction Work in Progress - - 4,084 55,075 183,800 100,426 - - 343,384 60 Net Plant in Service - - 112,592 976,121 3,288,346 8,278,211 - - 12,655,270 6162 Gas Stored Underground: - - - 1,823,680 - - - - 1,823,680 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 26,739 213,101 3,192,984 - - - 3,432,823 65 Materials & Supplies: - - - - 13,027 16,719 - - 29,746 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 1,925 2,170 39,641 - - - 43,736 68 Cash & Bank Balances - - 20,672 2,711 37,884 - - - 61,267 69 Property, Payroll & Income Taxes Accrued: - - (1,525) (9,856) (154,606) - - (165,987) 70 TOTAL RATE BASE - - 160,403 3,007,927 6,417,276 8,294,930 - - 17,880,535 71 % of Rate Base 0.0000% 0.0000% 0.8971% 16.8224% 35.8897% 46.3908% 0.0000% 0.0000% 100.0000%





Page 6 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: LARGE GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 1,557,202 1,557,202 5 Gas Supply Acquisition Cost 17,696 17,696 6 Production Demand 3,105 3,105 7 Storage Cost 11,046 11,046 8 Total - Production 1,557,202 17,696 3,105 11,046 - - - - 1,589,050 910 Transmission: 2,485 362 2,846 11 Distribution: 16,525 2,352 18,876 12 Customer Accounts and Services: - 13 Allocable 11,745 11,745 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 13,626 2,391 5,547 16,483 - 11,751 - 49,799 17 Total Operation & Maintenance Expense: 1,557,202 31,322 5,496 16,593 35,493 2,714 23,496 - 1,672,316 1819 Depreciation & Amort Expense: - - 469 7,526 18,419 3,639 - - 30,052 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 14 7 6 21 179 97 - 324 23 Retirement Benefits - FED 168 88 76 247 2,137 1,166 - 3,881 24 IBS Payroll Tax 93 49 42 137 1,185 646 - 2,151 25 Michigan SBT & Real Estate/Property - - 256 9,947 17,983 1,706 - - 29,892 26 Misc - Unauthorized Ins. Tax & Franchise - - 1 44 79 7 - - 131 27 Total Taxes Other Than Income Taxes: - 275 401 10,115 18,466 5,213 1,909 - 36,379 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 245 9,521 17,212 1,632 - - 28,611 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 1,557,202 31,597 6,611 43,755 89,590 13,198 25,405 - 1,767,358 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (21) (800) (1,446) (137) - - (2,403) 40 Acct 488, Acct 495: Miscellaneous 4,259 4,259 41 Acct 495: Customer Penalities & Gas True-up (143,876) (143,876) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (143,876) - (21) (800) (1,446) (137) 4,259 - (142,020) 4445 Actual Return (Net Operating Income) - - 1,605 62,247 112,533 10,673 - - 187,058 4647 Return Income Deficiency - - (497) (19,294) (34,881) (3,308) - - (57,981) 4849 Additional Income Taxes on Deficiency: - - 196 7,611 13,759 1,305 - - 22,870 5051 REVENUE REQUIREMENTS: 1,413,326 31,597 7,894 93,518 179,555 21,731 29,665 - 1,777,286 5253545556 RATE BASE:57 Utility Plant in Service - - 19,913 348,623 712,843 268,543 - - 1,349,921 58 Accumulated Depreciation - S/L - - (10,201) (164,214) (425,569) (169,788) - - (769,771) 59 Construction Work in Progress - - 365 11,027 16,483 4,445 - - 32,320 60 Net Plant in Service - - 10,077 195,436 303,756 103,200 - - 612,469 6162 Gas Stored Underground: - - - 365,133 - - - - 365,133 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 3,565 42,666 790,344 - - - 836,575 65 Materials & Supplies: - - - - 1,166 59 - - 1,225 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 172 434 3,551 - - - 4,158 68 Cash & Bank Balances - - 1,850 543 3,561 - - - 5,954 69 Property, Payroll & Income Taxes Accrued: - - (137) (1,973) (13,626) - - (15,736) 70 TOTAL RATE BASE - - 15,527 602,240 1,088,753 103,259 - - 1,809,778 71 % of Rate Base 0.0000% 0.0000% 0.8579% 33.2770% 60.1595% 5.7056% 0.0000% 0.0000% 100.0000%





Page 7 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 19,988 19,988 7 Storage Cost 17,368 17,368 8 Total - Production - - 19,988 17,368 - - - - 37,356 910 Transmission: 15,993 2,186 18,178 11 Distribution: 106,368 11,797 118,165 12 Customer Accounts and Services: - 13 Allocable 102,392 102,392 14 Transport Allocable 45,249 45,249 15 Customer Sales: - - 16 Administrative & General: - - 15,391 8,722 106,103 - 102,451 32,136 264,803 17 Total Operation & Maintenance Expense: - - 35,379 26,090 228,464 13,982 204,844 77,385 586,143 1819 Depreciation & Amort Expense: - - 3,017 11,833 118,560 20,494 - - 153,903 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 130 38 125 1,085 592 - 1,970 23 Retirement Benefits - FED 1,550 461 1,500 12,976 7,078 - 23,566 24 IBS Payroll Tax 859 255 831 7,192 3,923 - 13,061 25 Michigan SBT & Real Estate/Property - - 1,627 15,640 61,217 9,811 - - 88,295 26 Misc - Unauthorized Ins. Tax & Franchise - - 7 68 268 43 - - 386 27 Total Taxes Other Than Income Taxes: - - 4,174 16,463 63,941 31,107 11,593 - 127,278 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 1,558 14,970 58,595 9,390 - - 84,513 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 44,127 69,355 469,560 74,973 216,437 77,385 951,837 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (404) (3,883) (15,199) (2,436) - - (21,922) 40 Acct 488, Acct 495: Miscellaneous 13,587 13,587 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (404) (3,883) (15,199) (2,436) 13,587 - (8,334) 4445 Actual Return (Net Operating Income) - - 26,419 253,887 993,757 159,258 - - 1,433,322 4647 Return Income Deficiency - - (19,391) (186,352) (729,411) (116,895) - - (1,052,049) 4849 Additional Income Taxes on Deficiency: - - 1,245 11,966 46,838 7,506 - - 67,555 5051 REVENUE REQUIREMENTS: - - 51,996 144,974 765,545 122,407 230,024 77,385 1,392,331 5253545556 RATE BASE:57 Utility Plant in Service - - 128,176 548,145 4,588,538 1,562,714 - - 6,827,573 58 Accumulated Depreciation - S/L - - (65,665) (258,195) (2,739,369) (995,404) - - (4,058,634) 59 Construction Work in Progress - - 2,353 17,338 106,098 26,434 - - 152,222 60 Net Plant in Service - - 64,863 307,288 1,955,266 593,744 - - 2,921,161 6162 Gas Stored Underground: - - - 574,103 - - - - 574,103 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 21,531 67,085 1,785,980 - - - 1,874,596 65 Materials & Supplies: - - - - 7,505 233 - - 7,738 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 1,109 683 22,855 - - - 24,647 68 Cash & Bank Balances - - 11,909 853 22,719 - - - 35,481 69 Property, Payroll & Income Taxes Accrued: - - (879) (3,103) (87,963) - - (91,944) 70 TOTAL RATE BASE - - 98,533 946,910 3,706,362 593,977 - - 5,345,782 71 % of Rate Base 0.0000% 0.0000% 1.8432% 17.7132% 69.3325% 11.1111% 0.0000% 0.0000% 100.0000%





Page 8 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 40,615 40,615 7 Storage Cost 29,026 29,026 8 Total - Production - - 40,615 29,026 - - - - 69,641 910 Transmission: 32,496 4,733 37,229 11 Distribution: 216,136 4,036 220,172 12 Customer Accounts and Services: - 13 Allocable 107,315 107,315 14 Transport Allocable 15,556 15,556 15 Customer Sales: - - 16 Administrative & General: - - 31,273 14,576 215,598 - 107,376 11,048 379,872 17 Total Operation & Maintenance Expense: - - 71,888 43,602 464,230 8,770 214,691 26,605 829,785 1819 Depreciation & Amort Expense: - - 6,130 19,775 240,909 33,152 - - 299,966 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 261 78 253 2,187 1,193 - 3,971 23 Retirement Benefits - FED 3,126 929 3,024 26,162 14,271 - 47,511 24 IBS Payroll Tax 1,732 515 1,676 14,500 7,909 - 26,332 25 Michigan SBT & Real Estate/Property - - 3,354 26,138 116,172 17,143 - - 162,807 26 Misc - Unauthorized Ins. Tax & Franchise - - 15 114 508 75 - - 712 27 Total Taxes Other Than Income Taxes: - - 8,488 27,773 121,633 60,067 23,373 - 241,334 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 3,211 25,018 111,195 16,409 - - 155,833 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 89,717 116,169 937,966 118,397 238,064 26,605 1,526,918 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (494) (3,847) (17,099) (2,523) - - (23,964) 40 Acct 488, Acct 495: Miscellaneous 13,013 13,013 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (494) (3,847) (17,099) (2,523) 13,013 - (10,951) 4445 Actual Return (Net Operating Income) - - 21,935 170,919 759,659 112,100 - - 1,064,613 4647 Return Income Deficiency - - (7,450) (58,051) (258,009) (38,074) - - (361,584) 4849 Additional Income Taxes on Deficiency: - - 2,566 19,998 88,884 13,116 - - 124,565 5051 REVENUE REQUIREMENTS: - - 106,275 245,189 1,511,400 203,016 251,077 26,605 2,343,562 5253545556 RATE BASE:57 Utility Plant in Service - - 260,449 916,083 9,323,717 2,894,741 - - 13,394,990 58 Accumulated Depreciation - S/L - - (133,429) (431,507) (5,566,284) (1,912,225) - - (8,043,445) 59 Construction Work in Progress - - 4,780 28,976 215,586 55,323 - - 304,665 60 Net Plant in Service - - 131,800 513,552 3,973,019 1,037,839 - - 5,656,210 6162 Gas Stored Underground: - - - 959,466 - - - - 959,466 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 46,625 112,115 3,130,478 - - - 3,289,218 65 Materials & Supplies: - - - - 15,250 80 - - 15,330 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 2,253 1,142 46,449 - - - 49,844 68 Cash & Bank Balances - - 24,199 1,426 46,583 - - - 72,208 69 Property, Payroll & Income Taxes Accrued: - - (1,786) (5,185) (178,219) - - (185,190) 70 TOTAL RATE BASE - - 203,091 1,582,516 7,033,561 1,037,919 - - 9,857,086 71 % of Rate Base 0.0000% 0.0000% 2.0604% 16.0546% 71.3554% 10.5297% 0.0000% 0.0000% 100.0000%





Page 9 of 21


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 30,354 30,354 7 Storage Cost 25,688 25,688 8 Total - Production - - 30,354 25,688 - - - - 56,043 910 Transmission: 24,287 4,320 28,607 11 Distribution: 161,533 535 162,068 12 Customer Accounts and Services: - 13 Allocable 64,150 64,150 14 Transport Allocable 2,435 2,435 15 Customer Sales: - - 16 Administrative & General: - - 23,372 12,900 161,131 - 64,187 1,729 263,320 17 Total Operation & Maintenance Expense: - - 53,727 38,589 346,951 4,855 128,338 4,164 576,623 1819 Depreciation & Amort Expense: - - 4,581 17,502 180,048 28,630 - - 230,761 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 196 58 189 1,638 893 - 2,974 23 Retirement Benefits - FED 2,341 695 2,265 19,593 10,688 - 35,581 24 IBS Payroll Tax 1,297 385 1,255 10,859 5,924 - 19,721 25 Michigan SBT & Real Estate/Property - - 2,634 23,133 94,887 15,048 - - 135,701 26 Misc - Unauthorized Ins. Tax & Franchise - - 12 101 415 66 - - 594 27 Total Taxes Other Than Income Taxes: - - 6,480 24,373 99,011 47,203 17,504 - 194,571 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2,521 22,142 90,822 14,403 - - 129,888 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 67,309 102,605 716,831 95,092 145,842 4,164 1,131,843 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (283) (2,488) (10,205) (1,618) - - (14,594) 40 Acct 488, Acct 495: Miscellaneous 6,896 6,896 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (283) (2,488) (10,205) (1,618) 6,896 - (7,699) 4445 Actual Return (Net Operating Income) - - 8,498 74,623 306,089 48,541 - - 437,752 4647 Return Income Deficiency - - 2,877 25,268 103,646 16,437 - - 148,229 4849 Additional Income Taxes on Deficiency: - - 2,016 17,699 72,599 11,513 - - 103,826 5051 REVENUE REQUIREMENTS: - - 80,417 217,708 1,188,960 169,965 152,738 4,164 1,813,952 5253545556 RATE BASE:57 Utility Plant in Service - - 194,651 810,754 6,968,249 2,570,674 - - 10,544,328 58 Accumulated Depreciation - S/L - - (99,721) (381,893) (4,160,063) (1,709,849) - - (6,351,526) 59 Construction Work in Progress - - 3,573 25,644 161,122 50,216 - - 240,555 60 Net Plant in Service - - 98,503 454,505 2,969,308 911,041 - - 4,433,357 6162 Gas Stored Underground: - - - 849,149 - - - - 849,149 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 42,553 99,225 2,825,281 - - - 2,967,059 65 Materials & Supplies: - - - - 11,397 13 - - 11,410 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 1,684 1,010 34,737 - - - 37,432 68 Cash & Bank Balances - - 18,086 1,262 35,939 - - - 55,287 69 Property, Payroll & Income Taxes Accrued: - - (1,335) (4,589) (131,806) - - (137,730) 70 TOTAL RATE BASE - - 159,491 1,400,562 5,744,856 911,054 - - 8,215,963 71 % of Rate Base 0.0000% 0.0000% 1.9412% 17.0468% 69.9231% 11.0888% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: CUST CHOICE - RESID. GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 33,974 33,974 7 Storage Cost 47,850 47,850 8 Total - Production - - 33,974 47,850 - - - - 81,824 910 Transmission: 27,183 2,416 29,599 11 Distribution: 168,674 815,015 983,689 12 Customer Accounts and Services: - 13 Allocable 1,409,838 1,409,838 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 26,159 24,029 168,254 - 1,410,649 - 1,629,092 17 Total Operation & Maintenance Expense: - - 60,133 71,879 364,110 817,431 2,820,488 - 4,134,042 1819 Depreciation & Amort Expense: - - 5,128 32,600 195,181 735,574 - - 968,483 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 372 110 359 3,110 1,697 - 5,648 23 Retirement Benefits - FED 4,446 1,321 4,301 37,211 20,298 - 67,576 24 IBS Payroll Tax 2,464 732 2,384 20,624 11,250 - 37,453 25 Michigan SBT & Real Estate/Property - - 2,555 43,089 97,406 199,677 - - 342,727 26 Misc - Unauthorized Ins. Tax & Franchise - - 11 189 426 874 - - 1,499 27 Total Taxes Other Than Income Taxes: - - 9,847 45,441 104,876 261,495 33,244 - 454,903 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2,445 41,243 93,233 191,123 - - 328,045 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 77,554 191,164 757,400 2,005,622 2,853,732 - 5,885,472 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (521) (8,790) (19,870) (40,732) - - (69,912) 40 Acct 488, Acct 495: Miscellaneous (74,299) (74,299) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related (95,150) (95,150) 43 Total Other Operating Income: - - (521) (8,790) (115,020) (40,732) (74,299) - (239,361) 4445 Actual Return (Net Operating Income) - - 14,295 241,105 545,033 1,117,286 - - 1,917,720 4647 Return Income Deficiency - - (3,263) (55,038) (124,418) (255,049) - - (437,769) 4849 Additional Income Taxes on Deficiency: - - 1,955 32,968 74,526 152,774 - - 262,223 5051 REVENUE REQUIREMENTS: - - 90,019 401,409 1,137,522 2,979,901 2,779,433 - 7,388,285 5253545556 RATE BASE:57 Utility Plant in Service - - 217,862 1,510,188 7,575,750 25,904,202 - - 35,208,002 58 Accumulated Depreciation - S/L - - (111,612) (711,351) (4,535,822) (14,062,612) - - (19,421,397) 59 Construction Work in Progress - - 3,999 47,767 179,974 198,354 - - 430,094 60 Net Plant in Service - - 110,249 846,604 3,219,903 12,039,944 - - 16,216,699 6162 Gas Stored Underground: - - - 1,581,705 - - - - 1,581,705 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 23,799 184,825 2,740,998 - - - 2,949,623 65 Materials & Supplies: - - - - 12,756 49,372 - - 62,128 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 1,885 1,882 38,809 - - - 42,576 68 Cash & Bank Balances - - 20,242 2,351 36,748 - - - 59,341 69 Property, Payroll & Income Taxes Accrued: - - (1,494) (8,548) (151,818) - - (161,860) 70 TOTAL RATE BASE - - 154,681 2,608,820 5,897,395 12,089,316 - - 20,750,212 71 % of Rate Base 0.0000% 0.0000% 0.7454% 12.5725% 28.4209% 58.2612% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: CUST CHOICE - SMALL GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 35,793 35,793 7 Storage Cost 53,935 53,935 8 Total - Production - - 35,793 53,935 - - - - 89,728 910 Transmission: 28,638 2,800 31,438 11 Distribution: 177,702 393,579 571,281 12 Customer Accounts and Services: - 13 Allocable 510,089 510,089 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 27,560 27,085 177,260 - 510,382 - 742,287 17 Total Operation & Maintenance Expense: - - 63,352 81,020 383,600 396,379 1,020,471 - 1,944,823 1819 Depreciation & Amort Expense: - - 5,402 36,746 205,628 233,985 - - 481,762 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 265 79 256 2,218 1,210 - 4,028 23 Retirement Benefits - FED 3,171 942 3,067 26,539 14,477 - 48,196 24 IBS Payroll Tax 1,757 522 1,700 14,709 8,024 - 26,712 25 Michigan SBT & Real Estate/Property - - 2,733 48,569 104,301 86,085 - - 241,688 26 Misc - Unauthorized Ins. Tax & Franchise - - 12 212 456 377 - - 1,057 27 Total Taxes Other Than Income Taxes: - - 7,938 50,325 109,781 129,928 23,710 - 321,683 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2,616 46,489 99,833 82,397 - - 231,335 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 79,309 214,580 798,843 842,689 1,044,181 - 2,979,603 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (718) (12,765) (27,412) (22,625) - - (63,520) 40 Acct 488, Acct 495: Miscellaneous (8,576) (8,576) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related 102,119 102,119 43 Total Other Operating Income: - - (718) (12,765) 74,707 (22,625) (8,576) - 30,023 4445 Actual Return (Net Operating Income) - - 43,890 779,967 1,674,956 1,382,420 - - 3,881,233 4647 Return Income Deficiency - - (32,088) (570,236) (1,224,566) (1,010,692) - - (2,837,583) 4849 Additional Income Taxes on Deficiency: - - 2,091 37,161 79,802 65,864 - - 184,918 5051 REVENUE REQUIREMENTS: - - 92,483 448,706 1,403,742 1,257,657 1,035,606 - 4,238,194 5253545556 RATE BASE:57 Utility Plant in Service - - 229,524 1,702,249 7,981,266 10,814,913 - - 20,727,952 58 Accumulated Depreciation - S/L - - (117,586) (801,819) (4,778,616) (5,687,609) - - (11,385,630) 59 Construction Work in Progress - - 4,213 53,842 189,608 74,407 - - 322,070 60 Net Plant in Service - - 116,150 954,273 3,392,258 5,201,711 - - 9,664,391 6162 Gas Stored Underground: - - - 1,782,862 - - - - 1,782,862 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 27,584 208,331 2,988,679 - - - 3,224,594 65 Materials & Supplies: - - - - 13,439 10,242 - - 23,681 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 1,986 2,122 40,894 - - - 45,001 68 Cash & Bank Balances - - 21,326 2,650 39,081 - - - 63,057 69 Property, Payroll & Income Taxes Accrued: - - (1,574) (9,635) (159,491) - - (170,700) 70 TOTAL RATE BASE - - 165,472 2,940,602 6,314,860 5,211,953 - - 14,632,887 71 % of Rate Base 0.0000% 0.0000% 1.1308% 20.0958% 43.1553% 35.6181% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: CUST CHOICE - LARGE GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL







(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 26 26 7 Storage Cost 40 40 8 Total - Production - - 26 40 - - - - 66 910 Transmission: 21 2 22 11 Distribution: 127 357 484 12 Customer Accounts and Services: - 13 Allocable 716 716 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 20 20 127 - 717 - 884 17 Total Operation & Maintenance Expense: - - 45 60 275 359 1,433 - 2,172 1819 Depreciation & Amort Expense: - - 4 27 147 348 - - 527 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 0 0 0 2 1 - 4 23 Retirement Benefits - FED 3 1 3 24 13 - 44 24 IBS Payroll Tax 2 0 2 13 7 - 24 25 Michigan SBT & Real Estate/Property - - 2 36 80 93 - - 211 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 0 0 0 - - 1 27 Total Taxes Other Than Income Taxes: - - 7 38 85 132 21 - 283 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2 34 77 89 - - 202 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 58 159 584 928 1,455 - 3,184 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (0) (7) (16) (18) - - (42) 40 Acct 488, Acct 495: Miscellaneous 0 0 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related 15 15 43 Total Other Operating Income: - - (0) (7) (1) (18) 0 - (27) 4445 Actual Return (Net Operating Income) - - 12 231 514 594 - - 1,351 4647 Return Income Deficiency - - (4) (75) (168) (194) - - (441) 4849 Additional Income Taxes on Deficiency: - - 1 28 61 71 - - 161 5051 REVENUE REQUIREMENTS: - - 67 335 990 1,381 1,455 - 4,228 5253545556 RATE BASE:57 Utility Plant in Service - - 164 1,262 5,716 12,223 - - 19,367 58 Accumulated Depreciation - S/L - - (84) (595) (3,423) (6,741) - - (10,842) 59 Construction Work in Progress - - 3 40 136 102 - - 281 60 Net Plant in Service - - 83 708 2,430 5,585 - - 8,806 6162 Gas Stored Underground: - - - 1,322 - - - - 1,322 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 18 154 2,467 - - - 2,640 65 Materials & Supplies: - - - - 10 24 - - 34 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 1 2 29 - - - 32 68 Cash & Bank Balances - - 15 2 28 - - - 45 69 Property, Payroll & Income Taxes Accrued: - - (1) (7) (115) - - (123) 70 TOTAL RATE BASE - - 116 2,181 4,849 5,609 - - 12,755 71 % of Rate Base 0.0000% 0.0000% 0.9109% 17.0957% 38.0176% 43.9758% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 66 66 7 Storage Cost 106 106 8 Total - Production - - 66 106 - - - - 172 910 Transmission: 53 5 58 11 Distribution: 327 502 829 12 Customer Accounts and Services: - 13 Allocable 1,144 1,144 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 51 53 326 - 1,145 - 1,575 17 Total Operation & Maintenance Expense: - - 117 160 706 508 2,290 - 3,779 1819 Depreciation & Amort Expense: - - 10 72 378 423 - - 884 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 0 0 4 2 - 8 23 Retirement Benefits - FED 6 2 6 51 28 - 93 24 IBS Payroll Tax 3 1 3 28 15 - 51 25 Michigan SBT & Real Estate/Property - - 5 96 204 129 - - 434 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 0 1 1 - - 2 27 Total Taxes Other Than Income Taxes: - - 15 99 214 213 46 - 587 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 5 92 195 124 - - 415 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 146 423 1,494 1,267 2,335 - 5,665 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (2) (29) (61) (39) - - (130) 40 Acct 488, Acct 495: Miscellaneous 104 104 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related 224 224 43 Total Other Operating Income: - - (2) (29) 163 (39) 104 - 198 4445 Actual Return (Net Operating Income) - - 96 1,822 3,880 2,458 - - 8,256 4647 Return Income Deficiency - - (74) (1,408) (2,999) (1,900) - - (6,382) 4849 Additional Income Taxes on Deficiency: - - 4 73 156 99 - - 332 5051 REVENUE REQUIREMENTS: - - 170 881 2,694 1,885 2,439 - 8,069 5253545556 RATE BASE:57 Utility Plant in Service - - 422 3,355 14,688 17,036 - - 35,501 58 Accumulated Depreciation - S/L - - (216) (1,580) (8,794) (9,389) - - (19,980) 59 Construction Work in Progress - - 8 106 349 150 - - 613 60 Net Plant in Service - - 214 1,881 6,243 7,797 - - 16,134 6162 Gas Stored Underground: - - - 3,514 - - - - 3,514 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 51 411 6,223 - - - 6,685 65 Materials & Supplies: - - - - 25 25 - - 50 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 4 4 75 - - - 83 68 Cash & Bank Balances - - 39 5 72 - - - 116 69 Property, Payroll & Income Taxes Accrued: - - (3) (19) (293) - - (315) 70 TOTAL RATE BASE - - 305 5,796 12,345 7,822 - - 26,267 71 % of Rate Base 0.0000% 0.0000% 1.1602% 22.0659% 46.9968% 29.7771% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 31 31 7 Storage Cost 82 82 8 Total - Production - - 31 82 - - - - 114 910 Transmission: 25 2 28 11 Distribution: 156 144 300 12 Customer Accounts and Services: - 13 Allocable 215 215 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 24 41 155 - 215 - 436 17 Total Operation & Maintenance Expense: - - 55 124 336 147 430 - 1,091 1819 Depreciation & Amort Expense: - - 5 56 180 80 - - 321 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 0 0 0 2 1 - 3 23 Retirement Benefits - FED 3 1 3 22 12 - 39 24 IBS Payroll Tax 1 0 1 12 7 - 22 25 Michigan SBT & Real Estate/Property - - 2 74 151 35 - - 262 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 0 1 0 - - 1 27 Total Taxes Other Than Income Taxes: - - 7 76 155 70 19 - 327 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 2 71 144 33 - - 250 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 69 326 816 330 449 - 1,990 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (0) (11) (22) (5) - - (38) 40 Acct 488, Acct 495: Miscellaneous (3) (3) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related (880) (880) 43 Total Other Operating Income: - - (0) (11) (902) (5) (3) - (922) 4445 Actual Return (Net Operating Income) - - 28 862 1,753 403 - - 3,046 4647 Return Income Deficiency - - (18) (542) (1,103) (254) - - (1,917) 4849 Additional Income Taxes on Deficiency: - - 2 57 115 26 - - 200 5051 REVENUE REQUIREMENTS: - - 81 692 679 501 446 - 2,398 5253545556 RATE BASE:57 Utility Plant in Service - - 201 2,595 6,990 4,499 - - 14,285 58 Accumulated Depreciation - S/L - - (103) (1,222) (4,185) (2,444) - - (7,955) 59 Construction Work in Progress - - 4 82 166 39 - - 291 60 Net Plant in Service - - 102 1,455 2,971 2,094 - - 6,621 6162 Gas Stored Underground: - - - 2,718 - - - - 2,718 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 24 318 6,203 - - - 6,545 65 Materials & Supplies: - - - - 12 2 - - 14 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 2 3 36 - - - 41 68 Cash & Bank Balances - - 19 4 34 - - - 57 69 Property, Payroll & Income Taxes Accrued: - - (1) (15) (140) - - (155) 70 TOTAL RATE BASE - - 146 4,483 9,116 2,096 - - 15,841 71 % of Rate Base 0.0000% 0.0000% 0.9200% 28.2997% 57.5498% 13.2305% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)


12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 119 119 7 Storage Cost 280 280 8 Total - Production - - 119 280 - - - - 398 910 Transmission: 95 9 104 11 Distribution: 589 70 659 12 Customer Accounts and Services: - 13 Allocable 681 681 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - - 91 140 588 - 681 - 1,501 17 Total Operation & Maintenance Expense: - - 210 420 1,272 79 1,363 - 3,344 1819 Depreciation & Amort Expense: - - 18 190 682 102 - - 992 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 0 1 7 4 - 12 23 Retirement Benefits - FED 10 3 9 80 43 - 145 24 IBS Payroll Tax 5 2 5 44 24 - 80 25 Michigan SBT & Real Estate/Property - - 9 252 516 46 - - 823 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 1 2 0 - - 4 27 Total Taxes Other Than Income Taxes: - - 25 258 534 177 71 - 1,064 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 9 241 494 44 - - 788 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 261 1,109 2,982 402 1,434 - 6,188 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (2) (44) (90) (8) - - (144) 40 Acct 488, Acct 495: Miscellaneous 339 339 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related (3,532) (3,532) 43 Total Other Operating Income: - - (2) (44) (3,622) (8) 339 - (3,336) 4445 Actual Return (Net Operating Income) - - 140 3,873 7,944 707 - - 12,663 4647 Return Income Deficiency - - (100) (2,786) (5,714) (509) - - (9,108) 4849 Additional Income Taxes on Deficiency: - - 7 193 395 35 - - 630 5051 REVENUE REQUIREMENTS: - - 306 2,345 1,986 627 1,773 - 7,037 5253545556 RATE BASE:57 Utility Plant in Service - - 761 8,824 26,471 7,175 - - 43,232 58 Accumulated Depreciation - S/L - - (390) (4,157) (15,849) (4,509) - - (24,905) 59 Construction Work in Progress - - 14 279 629 116 - - 1,038 60 Net Plant in Service - - 385 4,947 11,251 2,782 - - 19,365 6162 Gas Stored Underground: - - - 9,242 - - - - 9,242 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 91 1,080 20,235 - - - 21,406 65 Materials & Supplies: - - - - 45 2 - - 47 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 7 11 136 - - - 154 68 Cash & Bank Balances - - 71 14 130 - - - 214 69 Property, Payroll & Income Taxes Accrued: - - (5) (50) (529) - - (584) 70 TOTAL RATE BASE - - 549 15,244 31,267 2,784 - - 49,844 71 % of Rate Base 0.0000% 0.0000% 1.1019% 30.5828% 62.7299% 5.5854% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: AGG TRNSPT - RESID. GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 107 107 7 Storage Cost 158 158 8 Total - Production - - 107 158 - - - - 265 910 Transmission: 86 8 93 11 Distribution: 532 1,215 1,747 12 Customer Accounts and Services: - 13 Allocable 2,205 2,205 14 Transport Allocable 14,136 14,136 15 Customer Sales: - - 16 Administrative & General: - - 83 79 531 - 2,206 10,039 12,938 17 Total Operation & Maintenance Expense: - - 190 238 1,148 1,223 4,411 24,176 31,385 1819 Depreciation & Amort Expense: - - 16 108 616 1,116 - - 1,855 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 1 0 1 8 4 - 14 23 Retirement Benefits - FED 11 3 11 92 50 - 168 24 IBS Payroll Tax 6 2 6 51 28 - 93 25 Michigan SBT & Real Estate/Property - - 8 143 320 311 - - 781 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 1 1 1 - - 3 27 Total Taxes Other Than Income Taxes: - - 26 149 339 463 82 - 1,059 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 8 136 306 297 - - 748 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 240 631 2,408 3,099 4,494 24,176 35,047 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (1) (24) (54) (52) - - (132) 40 Acct 488, Acct 495: Miscellaneous (49) (49) 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related (274) (274) 43 Total Other Operating Income: - - (1) (24) (328) (52) (49) - (455) 4445 Actual Return (Net Operating Income) - - (210) (3,718) (8,338) (8,106) - - (20,373) 4647 Return Income Deficiency - - 245 4,334 9,718 9,448 - - 23,745 4849 Additional Income Taxes on Deficiency: - - 6 109 245 238 - - 598 5051 REVENUE REQUIREMENTS: - - 279 1,331 3,705 4,627 4,445 24,176 38,562 5253545556 RATE BASE:57 Utility Plant in Service - - 687 4,996 23,893 40,856 - - 70,431 58 Accumulated Depreciation - S/L - - (352) (2,353) (14,305) (22,455) - - (39,465) 59 Construction Work in Progress - - 13 158 568 340 - - 1,078 60 Net Plant in Service - - 348 2,800 10,155 18,741 - - 32,044 6162 Gas Stored Underground: - - - 5,232 - - - - 5,232 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 75 611 9,398 - - - 10,085 65 Materials & Supplies: - - - - 40 73 - - 113 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 6 6 122 - - - 135 68 Cash & Bank Balances - - 64 8 116 - - - 188 69 Property, Payroll & Income Taxes Accrued: - - (5) (28) (479) - - (512) 70 TOTAL RATE BASE - - 488 8,630 19,353 18,814 - - 47,284 71 % of Rate Base 0.0000% 0.0000% 1.0314% 18.2504% 40.9284% 39.7897% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: AGG TRNSPT - SMALL GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 13,578 13,578 7 Storage Cost 19,398 19,398 8 Total - Production - - 13,578 19,398 - - - - 32,976 910 Transmission: 10,864 1,062 11,926 11 Distribution: 67,411 32,067 99,478 12 Customer Accounts and Services: - 13 Allocable 82,333 82,333 14 Transport Allocable 195,673 195,673 15 Customer Sales: - - 16 Administrative & General: - - 10,455 9,741 67,244 - 82,380 138,967 308,787 17 Total Operation & Maintenance Expense: - - 24,033 29,139 145,519 33,129 164,712 334,640 731,172 1819 Depreciation & Amort Expense: - - 2,049 13,216 78,005 26,134 - - 119,404 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 92 27 89 767 418 - 1,393 23 Retirement Benefits - FED 1,096 326 1,061 9,178 5,006 - 16,667 24 IBS Payroll Tax 608 181 588 5,087 2,775 - 9,237 25 Michigan SBT & Real Estate/Property - - 1,037 17,468 37,768 10,094 - - 66,366 26 Misc - Unauthorized Ins. Tax & Franchise - - 5 76 165 44 - - 290 27 Total Taxes Other Than Income Taxes: - - 2,837 18,078 39,671 25,169 8,199 - 93,954 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 992 16,720 36,150 9,661 - - 63,523 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 29,912 77,152 299,345 94,093 172,912 334,640 1,008,054 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (211) (3,561) (7,700) (2,058) - - (13,530) 40 Acct 488, Acct 495: Miscellaneous 3,297 3,297 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related 18,450 18,450 43 Total Other Operating Income: - - (211) (3,561) 10,750 (2,058) 3,297 - 8,217 4445 Actual Return (Net Operating Income) - - 6,992 117,800 254,700 68,069 - - 447,561 4647 Return Income Deficiency - - (2,515) (42,370) (91,611) (24,483) - - (160,980) 4849 Additional Income Taxes on Deficiency: - - 793 13,365 28,897 7,723 - - 50,778 5051 REVENUE REQUIREMENTS: - - 34,970 162,385 502,081 143,344 176,209 334,640 1,353,630 5253545556 RATE BASE:57 Utility Plant in Service - - 87,070 612,214 3,027,693 1,407,330 - - 5,134,306 58 Accumulated Depreciation - S/L - - (44,606) (288,374) (1,812,768) (813,487) - - (2,959,235) 59 Construction Work in Progress - - 1,598 19,364 71,928 16,260 - - 109,150 60 Net Plant in Service - - 44,062 343,204 1,286,853 610,103 - - 2,284,222 6162 Gas Stored Underground: - - - 641,206 - - - - 641,206 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 10,464 74,926 1,024,869 - - - 1,110,259 65 Materials & Supplies: - - - - 5,098 1,008 - - 6,106 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 753 763 15,513 - - - 17,029 68 Cash & Bank Balances - - 8,090 953 14,825 - - - 23,869 69 Property, Payroll & Income Taxes Accrued: - - (597) (3,465) (60,503) - - (64,565) 70 TOTAL RATE BASE - - 62,772 1,057,587 2,286,655 611,111 - - 4,018,125 71 % of Rate Base 0.0000% 0.0000% 1.5622% 26.3204% 56.9085% 15.2089% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: AGG TRNSPT - LARGE GS GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost - - 5 Gas Supply Acquisition Cost - - 6 Production Demand 274 274 7 Storage Cost 730 730 8 Total - Production - - 274 730 - - - - 1,004 910 Transmission: 219 32 251 11 Distribution: 1,460 210 1,669 12 Customer Accounts and Services: - 13 Allocable 1,791 1,791 14 Transport Allocable 1,184 1,184 15 Customer Sales: - - 16 Administrative & General: - - 211 366 1,456 - 1,792 841 4,666 17 Total Operation & Maintenance Expense: - - 485 1,096 3,135 242 3,582 2,024 10,565 1819 Depreciation & Amort Expense: - - 41 497 1,627 330 - - 2,496 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 2 1 2 16 8 - 28 23 Retirement Benefits - FED 22 7 21 186 101 - 337 24 IBS Payroll Tax 12 4 12 103 56 - 187 25 Michigan SBT & Real Estate/Property - - 23 657 1,172 152 - - 2,004 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 3 5 1 - - 9 27 Total Taxes Other Than Income Taxes: - - 59 671 1,212 457 166 - 2,565 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 22 629 1,122 145 - - 1,918 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: - - 608 2,893 7,096 1,174 3,748 2,024 17,543 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (4) (123) (219) (28) - - (374) 40 Acct 488, Acct 495: Miscellaneous 271 271 41 Acct 495: Customer Penalities & Gas True-up - - 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: - - (4) (123) (219) (28) 271 - (104) 4445 Actual Return (Net Operating Income) - - 260 7,551 13,467 1,746 - - 23,025 4647 Return Income Deficiency - - (162) (4,714) (8,407) (1,090) - - (14,373) 4849 Additional Income Taxes on Deficiency: - - 17 503 897 116 - - 1,533 5051 REVENUE REQUIREMENTS: - - 719 6,110 12,834 1,918 4,019 2,024 27,623 5253545556 RATE BASE:57 Utility Plant in Service - - 1,759 23,027 62,965 23,924 - - 111,675 58 Accumulated Depreciation - S/L - - (901) (10,847) (37,590) (15,124) - - (64,462) 59 Construction Work in Progress - - 32 728 1,456 395 - - 2,612 60 Net Plant in Service - - 890 12,909 26,831 9,195 - - 49,825 6162 Gas Stored Underground: - - - 24,118 - - - - 24,118 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 315 2,818 44,592 - - - 47,725 65 Materials & Supplies: - - - - 103 6 - - 109 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - 15 29 314 - - - 357 68 Cash & Bank Balances - - 163 36 315 - - - 513 69 Property, Payroll & Income Taxes Accrued: - - (12) (130) (1,204) - - (1,346) 70 TOTAL RATE BASE - - 1,371 39,779 70,950 9,201 - - 121,302 71 % of Rate Base 0.0000% 0.0000% 1.1303% 32.7938% 58.4907% 7.5853% 0.0000% 0.0000% 100.0000%






(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

GAS SUPPLY DISTRIBUTION DISTRIBUTION ENHANCEDLINE PURCHASED ACQUISITION PRODUCTION STORAGE DEMAND CUSTOMER OTHERNO. RATE: SPECIAL CONTRACT GAS COST COST DEMAND COST RELATED RELATED CUSTOMER SERVICES TOTAL

12 Operation & Maintenance Expense:3 Production:4 Purchased Gas Cost 1,340 1,340 5 Gas Supply Acquisition Cost 15 15 6 Production Demand 3 3 7 Storage Cost 18 18 8 Total - Production 1,340 15 3 18 - - - - 1,376 910 Transmission: 2 0 2 11 Distribution: 14 75 90 12 Customer Accounts and Services: - 13 Allocable 4,981 4,981 14 Transport Allocable - - 15 Customer Sales: - - 16 Administrative & General: - 12 2 9 14 - 4,983 - 5,021 17 Total Operation & Maintenance Expense: 1,340 27 5 27 31 76 9,964 - 11,469 1819 Depreciation & Amort Expense: - - 0 12 16 45 - - 73 2021 Taxes Other Than Income Taxes:22 Unemployment Comp - FED & STATE 0 0 0 0 0 0 - 0 23 Retirement Benefits - FED 0 0 0 0 3 1 - 5 24 IBS Payroll Tax 0 0 0 0 1 1 - 3 25 Michigan SBT & Real Estate/Property - - 0 16 30 16 - - 62 26 Misc - Unauthorized Ins. Tax & Franchise - - 0 0 0 0 - - 0 27 Total Taxes Other Than Income Taxes: - 0 0 16 30 20 2 - 70 2829 Other Income Before Income Taxes: - - - - - - - - - 3031 Income Taxes - - 0 16 29 15 - - 59 32 ITC - - - - - - - - - 3334 Other Income After Income Taxes: - - - - - - - - - 3536 TOTAL EXPENSES: 1,340 27 6 71 105 156 9,966 - 11,672 3738 Other Operating Income (Revenue Credits):39 Acct 487, Acct 493, Acct 495: IL Tax Fee - - (4) (288) (529) (281) - - (1,102) 40 Acct 488, Acct 495: Miscellaneous (3) (3) 41 Acct 495: Customer Penalities & Gas True-up (124) (124) 42 Acct 495: VBA and Decoupling related - - 43 Total Other Operating Income: (124) - (4) (288) (529) (281) (3) - (1,229) 4445 Actual Return (Net Operating Income) - - 405 29,108 53,586 28,454 - - 111,554 4647 Return Income Deficiency - - (404) (29,038) (53,457) (28,386) - - (111,286) 4849 Additional Income Taxes on Deficiency: - - 0 12 23 12 - - 48 5051 REVENUE REQUIREMENTS: 1,217 27 3 (134) (272) (45) 9,963 - 10,759 5253545556 RATE BASE:57 Utility Plant in Service - - 17 569 614 1,962 - - 3,161 58 Accumulated Depreciation - S/L - - (9) (268) (366) (1,016) - - (1,659) 59 Construction Work in Progress - - 0 18 14 12 - - 45 60 Net Plant in Service - - 9 319 261 958 - - 1,546 6162 Gas Stored Underground: - - - 595 - - - - 595 63 Fuel Stock - - - - - - - - - 64 Working Capital Allowance - - 3 70 1,550 - - - 1,623 65 Materials & Supplies: - - - - 1 2 - - 3 66 Other - Deferred Taxes (M&S / CWIP) - - - - - - - - - 67 Prepayments - - - 1 3 - - - 4 68 Cash & Bank Balances - - 2 1 3 - - - 6 69 Property, Payroll & Income Taxes Accrued: - - - (3) (12) - - (15) 70 TOTAL RATE BASE - - 14 982 1,807 960 - - 3,762 71 % of Rate Base 0.0000% 0.0000% 0.3635% 26.0935% 48.0361% 25.5069% 0.0000% 0.0000% 100.0000%





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Page 1 of 3

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Page 2 of 3

Mic

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Page 3 of 3

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Page 2 of 4

Mic

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Page 1 of 1

STATE OF MICHIGAN




DAVID J. TYLER

FOR


June 7, 2013

- 2 -

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

DAVID J. TYLER PART I


A. My name is David J. Tyler. My business address is 899 S. Telegraph, Monroe, 2

Michigan 48161. I am Manager, Regulatory Services for Michigan Gas Utilities 3

Corporation (“MGUC”). MGUC is a wholly-owned subsidiary of Integrys Energy 4

Group, Inc. (“Integrys”). Integrys resulted from the February 21, 2007 merger 5

between WPS Resources Corporation and Peoples Energy Corporation. 6

7



10

Q. Briefly describe your educational, professional, and utility background. 11

A. I graduated from Wayne State University in 1976 with a Bachelor of Science Degree 12

in Business Administration, majoring in Accounting. 13

14

From 1976 to 1987, I was employed by ANR Pipeline Company progressing through 15

positions of increasing responsibility and authority in the following departments: 16

Special Projects, General Accounting, General Ledger Operations, Gas Accounting, 17

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and finally, Supervisor - Gas Accounting and Control with responsibility for the 1

monthly invoicing of all the pipeline sales customers. 2

3

In October 1987, I accepted a position with MGUC’s predecessor, Aquila Inc., d/b/a 4

Aquila Networks – MGU (“MGU/Aquila”) as a Tariff and Contract Administrator where 5

I was responsible for monitoring and controlling purchase contracts related to system 6

supplies and end-user transportation. In November 1989, I was promoted to Federal 7

Regulatory Analyst responsible for monitoring and analyzing activities at the Federal 8

Energy Regulatory Commission (“FERC”) to determine their impact upon MGUC, as 9

well as developing and recommending the positions that MGUC would take in 10

various proceedings. In July 1990, I was promoted to the position of Manager – 11

Federal Regulatory Affairs. 12

13

In August 1994, I accepted a position with SEMCO Energy Gas Company 14

(“SEMCO”) as Manager, Federal Regulatory Affairs. 15

16

In June 2001, I returned to MGU/Aquila, in my current position for MGUC, as 17

Manager, Regulatory Services for the state of Michigan. In this position, I am 18

responsible for regulatory activities within the state, including: (1) insuring 19

compliance with all Michigan Public Service Commission (“MPSC” or “Commission”) 20

orders; (2) acting as a liaison with the MPSC Staff and interveners; (3) serving as 21

the Integrys representative on the Efficiency United Steering Committee (the state 22

appointed administrator for energy optimization (“EO”) programs); and (4) providing 23

support to business unit leaders throughout the Integrys organization. In addition to 24

these duties, I am responsible for preparing analyses related to and setting MGUC’s, 25

monthly Gas Cost Recovery (“GCR”) factors, preparing the monthly 45-Day Report, 26

GCR plan and reconciliation filings, as well as EO filings. 27

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1


A. Yes, I have. I have testified before the MPSC in numerous MGU/Aquila, SEMCO 3

and MGUC GCR plan and reconciliation proceedings, and in connection with take-or-4

pay proceedings involving FERC Order Nos. 500 & 528. I sponsored testimony in 5

SEMCO’s 1996 general rate case proceeding (Case No. U-11220); MGU/Aquila’s 6

2002 general rate case proceeding (Case No. U-13470), and MGUC’s general rate 7

proceedings (Case Nos. U-15549 and U-15990). I also sponsored testimony in 8

MGUC’s 2009, 2010, 2011 and 2012 EO plan and reconciliation (Case Nos. U-9

15891, U-16291, U-16292, U-16752, U-16731 and U-17290, respectively). 10

11

I have also testified before the FERC on behalf of SEMCO in ANR Pipeline’s 1994 12

general rate case proceeding, Docket No. RP94-043. 13

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DAVID J. TYLER DIRECT TESTIMONY

PART II

Q. What is the purpose of your pre-filed direct testimony in this proceeding? 1

A. The purpose of my pre-filed direct testimony is to support the development and 2

presentation of MGUC’s rate design, and the proposed tariff sheet changes. 3

4


A. Yes, I am. I am sponsoring the following exhibits: 6

1. Exhibit A-6 (DJT-1), Schedule F2.1, 7 8 2. Exhibit A-6 (DJT-1), Schedule F2.2, 9

10 3. Exhibit A-6 (DJT-1), Schedule F3.1, 11

12 4. Exhibit A-6 (DJT-1), Schedule F3.2, 13

14 5. Exhibit A-6 (DJT-1), Schedule F4, 15

16 6. Exhibit A-6 (DJT-1), Schedule F5, and 17

18 7. Exhibit A-6 (DJT-1), Schedule F6. 19

20

Q. Did you cause these exhibits to be prepared? 21

A. Yes, I did. 22

23

Q. Please describe Exhibit A-6 (DJT-1), Schedule F2.1. 24

A. Exhibit A-6 (DJT-1), Schedule F2.1 is a one page summary showing for each rate 25

schedule the: 26

1. Revenues on Present Rates, including the cost of gas, 27

2. Revenues on Proposed Rates, including the cost of gas, 28

3. The proposed rate increase in dollars, including the cost of gas, and 29

4. The proposed rate increase in percent, including the cost of gas. 30

31

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A. Exhibit A-6 (DJT-1), Schedule F2.2 is a one page summary showing for each rate 2

schedule the: 3

1. Revenues on Present Rates, excluding the cost of gas, 4

2. Revenues on Proposed Rates, excluding the cost of gas, 5

3. The proposed rate increase in dollars, excluding the cost of gas, and 6

4. The proposed rate increase in percent, excluding the cost of gas. 7

8


A. Exhibit A-6 (DJT-1), Schedule F3.1 shows a detailed computation, by billing 10

determinant, for each rate schedule the: 11

1. Revenues on Present Rates, including the cost of gas, 12

2. Revenues on Proposed Rates, including the cost of gas, 13

3. The proposed rate increase in dollars, including the cost of gas, and 14

4. The proposed rate increase in percent, including the cost of gas. 15

16


A. Exhibit A-6 (DJT-1), Schedule F3.2 shows a detailed computation, by billing 18

determinant, for each rate schedule the: 19

1. Revenues on Present Rates, excluding the cost of gas, 20

2. Revenues on Proposed Rates, excluding the cost of gas, 21

3. The proposed rate increase in dollars, excluding the cost of gas, and 22

4. The proposed rate increase in percent, excluding the cost of gas. 23

24

Q. Please describe Exhibit A-6 (DJT-1), Schedule F4. 25

A. Exhibit A-6 (DJT-1), Schedule F4 is a comparison of typical monthly bills under 26

present and proposed rates for each rate class. 27

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1


A. Exhibit A-6 (DJT-1), Schedule F5 are proposed revised tariff sheets in redline format. 3

4


A. Exhibit A-6 (DJT-1), Schedule F6 is the calculation of the proposed interim rate 6

surcharges. 7

8

The Development and Presentation of the Proposed Rate Design 9 Q. What factors did MGUC consider when developing its proposed rate design? 10

A. The following factors were considered when developing the proposed rate design: 11

1. The Cost of Service Study (“COSS”) completed by Ms. Joylyn C. Hoffman 12 Malueg, specifically Exhibit A-6 (JCHM-1), Schedule F1.4, 13

14 2. The movement of customer rates toward the actual cost of service, 15 16 3. The minimization of cross-subsidizations between rate schedules, and 17 18 4. The avoidance of large bill impacts or “rate shock”. 19

20

Q. Please explain how the COSS influenced the proposed rate design. 21

A. Consistent with cost causation ratemaking principles, MGUC is proposing to move its 22

distribution rates toward the actual cost of providing distribution service to the various 23

customer classes, as calculated by the COSS completed by Ms. Joylyn C. Hoffman 24

Malueg and shown in her Exhibit A-6 (JCHM-1). To that end, MGUC is proposing 25

adjustments in the monthly customer charges to better match the monthly fixed costs 26

incurred by MGUC in providing distribution services to these rate schedules. 27

28

Q. Please explain how the cost similarities and differences inherent to providing 29

distribution services to system sales, transportation and Choice customers 30

influenced the proposed rate design. 31

A. MGUC’S rate design is based upon the following conclusions from the COSS: 32

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1. The only significant fixed cost difference between providing distribution 1 services to a transportation customer as compared to providing 2 distribution services to a system sales customer with the same load 3 characteristics is the cost associated with administering the more 4 complicated transportation accounts. 5

6 2. The only significant variable or “per Mcf “ cost difference between 7

providing distribution services to a system sales customer as compared 8 to providing distribution services to transportation and Choice customers 9 with the same load characteristics is the cost associated with 10 administering the gas supply and procurement functions. 11

12

These assumptions are reflected in the grouping of rate schedules in Ms. Joylyn C. 13

Hoffman Malueg’s Exhibit A-6 (JCHM-1). 14

15

Q. Are the assumptions listed above reasonable? 16

A. Yes they are, because they lead to a reasonable match between cost causation and 17

cost recovery. 18

19

Daily and Monthly Customer Charges 20 Q. Please describe the Customer Charge. 21

A. The Customer Charge is designed to recover a portion of the fixed costs of 22

transporting gas across the MGUC distribution system, regardless of whether the 23

gas commodity is being purchased from MGUC or a third party. Based on this 24

concept and the assumptions listed above, all similarly sized customers, whether 25

they are system sales, transportation or Choice customers, have equal Customer 26

Charges in the proposed rate design. 27

28

MGUC is proposing to identify its Customer Charge on both a Daily and Monthly 29

basis. The reasoning behind establishing a separate “Daily” Customer Charge is to 30

eliminate any difficulties in situations where prorating the Monthly Customer Charge 31

may be required. This generally occurs when a billing period may be less than or 32

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extend beyond the normal 30 day period; this could be the result of meter reading 1

route changes, termination of service, or other situations. 2

3

Q. Has the Commission approved Daily customer charges for any other Michigan 4

Utilities? 5

A. Yes, it has. The Commission has authorized Daily customer charges for Upper 6

Peninsula Power Company, and for both Wisconsin Public Service Corporation’s 7

electric and gas operations. 8

9

Q. Is it reasonable for similarly sized system sales customers to have the same 10

Customer Charge as transportation and Choice customers? 11

A. Yes, it is. Due to the robust nature of MGUC’s distribution system, the likelihood of 12

interruption due to a distribution system constraint is small. Therefore, it is 13

reasonable for all similarly sized customers to pay the same Customer Charge. In 14

addition to the Customer Charge, transportation customers will pay an Enhanced 15

Administrative fee. This fee recovers the costs associated with administering the 16

more complicated transportation accounts. 17

18

Distribution Rates 19 Q. Please describe the proposed distribution rates. 20

A. The traditional distribution margin rate can be separated into two components: 21

1. A distribution service volumetric fee, and 22 2. A gas supply acquisition fee. 23

24

Q. Please describe the distribution service volumetric fee component in the 25

distribution rates. 26

A. The distribution service volumetric fee component recovers any remaining fixed 27

costs that are not recovered through the customer charge, as well as the variable 28

costs of transporting gas across MGUC’s distribution system, regardless if the gas 29

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commodity is purchased from MGUC, taken from MGUC’s storage, or purchased 1

from a third party. Also included in the volumetric fee is a storage component which 2

recovers the costs of MGUC’s on-system storage facilities. This storage component 3

is shown as a separate item in the COSS, but was included in the rate design as a 4

part of the distribution service volumetric fee. In the rate design proposed here, all 5

similarly sized customers, whether they are system sales, transportation or Choice 6

customers, have equal distribution volumetric fees, as shown on Exhibit A-6 (DJT-1), 7

Schedules F3.1 and F3.2. 8

9

Q. Is it reasonable for similarly sized system sales customers to pay the same 10

distribution service volumetric fee component as transportation and Choice 11

customers? 12

A. Yes, it is. Due to the robust nature of MGUC’s distribution system, the likelihood of 13

interruption due to distribution system constraints is small. Therefore, it is 14

reasonable for all similarly sized customers to pay the same distribution service 15

volumetric fee component. 16

17

Q. Please describe the Gas Supply Acquisition component of the distribution 18

rates. 19

A. The Gas Supply Acquisition component is designed to recover the costs associated 20

with administering MGUC’s gas merchant function. 21

22

MGUC has calculated that the costs associated with administering the gas merchant 23

function to be equal to $806,308 for the 2014 projected test year. Specifically, the 24

gas merchant function costs primarily include the costs associated with the MGUC 25

Gas Supply Department, along with taxes and Administrative and General (“A&G”) 26

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expense loadings. This equates to a charge of approximately $0.055 per Mcf for 1

GCR customers. 2

3

Q. Is it reasonable for system sales customers to pay a Gas Supply Acquisition 4

component, while transportation and Choice customers do not? 5

A. Yes, it is. Because system sales customers are directly benefiting from MGUC’s gas 6

merchant function, it is reasonable for these customers to pay a Gas Supply 7

Acquisition component. Transportation and Choice customers receive this service 8

from their own suppliers, and not MGUC. 9

10

While MGUC’s currently approved rate design does not include a distinct Gas Supply 11

Acquisition component, MGUC proposes to include a Gas Supply Acquisition 12

component in its rates for GCR customers emerging from the instant general rate 13

case proceeding. 14

15

Movement of the Daily/Monthly Customer Charge Toward Cost of Service 16 Q. What is MGUC's proposed Customer Charge for Residential service? 17

A. MGUC’s current Monthly Customer Charge is $11.00. The COSS prepared by Ms. 18

Joylyn C. Hoffman Malueg, specifically Exhibit A-6 (JCHM-1), however, supports a 19

$22.35 Monthly Customer Charge. In an effort to moderate the amount of the 20

increase, MGUC is proposing that the Monthly Customer Charge for Residential 21

customers only be increased to $12.00. Although this represents a 9% increase over 22

the current rate, it is still well below the $22.35 rate justified in the COSS. As 23

previously mentioned, the Company is proposing to distinguish the Customer Charge 24

on a “Daily” and “Monthly” basis for administrative efficiency. 25

26

Q. Why is MGUC proposing an increase to the Customer Charge? 27

A. MGUC is proposing to move the Customer Charge closer to the rate recommended 28

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by its COSS. MGUC believes that if a Customer Charge is an appropriate method 1

for recovering costs from customers, then the transition of the rate toward cost of 2

service must move forward in order to eliminate the subsidization of low load factor 3

customers by high load factor customers. While MGUC realizes that there will be 4

some customers who will be negatively impacted by this change, other customers 5

are being negatively impacted by the current rate levels. MGUC must balance the 6

needs of all of its customers, some of whom will benefit from the change. MGUC 7

believes that its proposed rates are an appropriate compromise between the two 8

groups of customers during the transition of the Monthly Customer Charge rates 9

toward the actual cost of service. 10

11

Q. How does MGUC’s proposed Customer Charge compare with other Michigan 12

utilities? 13

A. The table below shows the Customer Charges currently authorized for other 14

Michigan gas utilities: 15

Customer 16 Utility Charge 17

Consumers Energy $10.50 18 DTE Energy (formerly MichCon) 10.73 19 Michigan Gas Utilities Corp. 12.00 (proposed) 20 Presque Isle E & G Co Op 12.00 21 SEMCO Energy 11.75 22 23

MGUC’s proposed Customer Charge would equal the highest authorized Customer 24

Charge in Michigan. 25

26

Cross-Subsidization Between Rate Schedules 27 Q. Please explain how MGUC's attempt to reduce the amount of cross-28

subsidization between the various rate schedules has influenced the rate 29

design MGUC has proposed. 30

A. Schedule F1.2 of Exhibit A-6 (JCHM-1), MGUC's 2014 Projected COSS – Detailed 31

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Summary completed by Ms. Joylyn C. Hoffman Malueg, indicates that the 1

Residential and Multi-Family Class I, Customer Choice – Residential, Customer 2

Choice – Multi-Family Class I, Aggregated – Residential and Aggregated – Small GS 3

rate schedules are being heavily subsidized by the other rate schedules. With 4

MGUC’s proposed rate design, MGUC has attempted to reduce the amount of cross-5

subsidization between the rate schedules by increasing the amount of revenue 6

collected from the Residential and Multiple-Family Class I, Customer Choice – 7

Residential, Aggregated – Residential and Aggregated – Small GS rate schedules. 8

Although MGUC’s rate design does not eliminate all cross-subsidization between 9

rate schedules, it provides appropriate movement toward that goal while considering 10

rate shock and other factors. 11

12

Q. The monthly fixed charges for TR-1, TR-2 and TR-3 rates have not been 13

adjusted, while the COSS demonstrates that a reduction is appropriate for TR-14

1 and TR-2 rates and a slight increase is appropriate for TR-3 rates. Please 15

explain. 16

A. As previously mentioned, the Company must consider the impact of rate changes it 17

is proposing on each of its customers. Shifting charges between Transportation and 18

General Service customers, in an effort to reduce cross-subsidization between rate 19

classes, cannot be made immediately. This would negatively impact one class over 20

the other. Therefore, such changes are made over time through a process known as 21

“gradualism”. In this process, the Company adjusts its rates to more appropriately 22

reflect its actual cost of service, while considering such issues as “rate shock”` and 23

other factors. 24

25

Elimination of the Multi-Family Dwelling Rate 26 Q. Please explain why MGUC is proposing to eliminate the Multi-Family Dwelling 27

rate. 28

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A. The Company is endeavoring to simplify its rate design which it believes will lead to 1

less confusion on the part of customers. By eliminating the Multi-Family rate class, 2

customer billings will be more consistent across classes, and it will reduce the total 3

number of classifications available. Currently, there are four different classifications 4

for Multi-Family service; each classification is differentiated by the hourly flow of gas. 5

Class I is designated as less than 400 cubic feet per hour (“CFH”); Class II is for 400 6

to 1,000 CFH and Classes III and IV are for customers that burn over 1,000 CFH. 7

The differentiation between Class III and Class IV has to do with whether or not there 8

is a pressure or temperature correcting device associated with the meter. Most 9

customers have no understanding of these types of differentiation and it often leads 10

to confusion and or frustration when a customer reviews tariff schedules in an 11

attempt to determine which rate class they would fall into. By eliminating the 12

classification entirely, customer confusion will be reduced. 13

14

For the 2014 projected test year, MGUC forecasts a total of 463 customers taking 15

service under the Multi-Family rate; 164 in Class I, 260 in Class II, 17 in Class III and 16

22 in Class IV. While there are not many customers in these rate classes, 17

elimination of this service classification will require fewer field inspections to 18

determine if customers are on the appropriate rate. The Company believes that 19

these benefits will outweigh the impact that a change in classifications may have on 20

any individual customer when shifting from the Multi-Family classification to either 21

Residential or Small General Service. Customers currently designated as Multi-22

Family Class I would be moved to Residential service and the other Multi-Family 23

classes would be moved to Small General service. 24

25

26

27

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Proposed Tariff Sheet Changes 1 Q. Please explain Exhibit A-6 (DJT-1), Schedule No. F5. 2

A. Exhibit A-6 (DJT-1), Schedule F5, pages 1 – 3 summarize the changes being 3

proposed for MGUC’s natural gas tariff. Pages 4 – 24 are redlined versions of the 4

proposed tariff sheets. 5

6

Q. What revision is MGUC proposing on Tariff Sheet No. C-23.00? 7

A. The Company is inserting language which requires that a customer’s account must 8

be “current” before they will be allowed to switch from one type of service or rate 9

classification to another. The Company does, however, reserve the right to waive the 10

requirement. 11

12


A. The Company is inserting language that clarifies the term “month”, as it applies to 14

customer billings. 15

16


A. The Company is proposing to modify its existing language to reflect recent changes 18

in its operating practices. The Company now installs a gas meter at the time that it 19

runs a gas service line, as such the Fixed Monthly Surcharge under the Customer 20

Attachment Program may now be assessed when the Company installs the meter. 21

22


A. The Company has inserted language that clarifies in instances where there are 24

multiple metered installations, the connection fee shall be $200.00 for the first 25

account and $100.00 for each subsequent account. 26

27

28

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Q. What revision is MGUC proposing on Tariff Sheet No. D-1.00? 1

A. This tariff sheet details the interim rate surcharges applicable to each of MGUC’s 2

various rate schedules. The surcharge rates represent an equal percentage 3

increase of margin revenues on present rates for each rate schedule, as calculated 4

on Exhibit A-6 (DJT-1), Schedule F6. 5

6

Q. What revisions is MGUC proposing on Tariff Sheet No. D-1.02? 7

A. The Company has moved the Energy Optimization Surcharge here, due to space 8

limitations on page D-1.00 and D-1.01 and eliminated its Revenue Decoupling 9

Mechanism for 2010, as it is no longer in effect 10

11


A. The Company has added the designation of a Daily Customer Charge, for 13

administrative purposes. The Customer and Distribution Charges have been updated 14

consistent with MGUC’s proposed rate design. The new rates are $12.00 per month, 15

and $1.7815 per Mcf, respectively. 16

17

Q. What revisions is MGUC proposing on Tariff Sheets No. D-7.00 through 18

D-10.00? 19

A. Language applicable to the Multi-Family Dwelling Rate has been eliminated as the 20

Company is proposing to consolidate this rate with the Residential Small General 21

Service classifications. 22

23




consistent with MGUC’s proposed rate design. The Monthly Customer Charge 27

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remains unchanged at $33.00 per month, and the new Distribution Charge is 1

$1.7815 per Mcf. 2

3




consistent with MGUC’s proposed rate design. The Monthly Customer Charge 7

remains unchanged at $400.00 per month, and the new Distribution Charge is 8

$1.0578 per Mcf. 9

10


A. The Distribution Charges have been updated consistent with MGUC’s proposed rate 12

design. The new rate is $1.7815 per Mcf. Additional language has been added to 13

include the Supplemental Charges that may apply. 14

15

Q. What revisions is MGUC proposing on Tariff Sheet No. E-13.00? 16

A. Charges for Transportation customers have been updated consistent with MGUC’s 17

proposed rate design, as shown below: 18

19

TR-1 TR-2 TR-3 20 Customer Charge $850.00 $2,250.00 $3,050.00 21 22 Transportation Rates: 23 Peak (Nov – Mar) $0.7777 per Mcf $0.4796 per Mcf $0.4651 per Mcf 24 Off-Peak (Apr – Oct) $0.6277 per Mcf $0.3296 per Mcf $0.3151 per Mcf 25 26

The only charge that has been revised for Transportation customers is the Monthly 27

Customer Charge for TR-1 customers, all other charges and rates remain 28

unchanged. Additional language has been added to include the Supplemental 29

Charges that may apply. 30

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1


A. MGUC is proposing to update its Gas-In-Kind retention percentage. MGUC has 3

updated its throughput, Company Use, and Gas Lost-and-Unaccounted-For figures 4

to reflect the last five year’s activity. The percentage has decreased to 0.31%. 5

6


A. MGUC is proposing to include the month of November in its storage injection 8

restrictions. Although November is generally considered one of the typical “winter 9

months”, the Company may still be injecting gas into its storage accounts and as 10

such, needs to expand its Authorized Tolerance Level (“ATL”) restrictions to include 11

the month of November. 12

13

Q. What revisions is MGUC proposing on Tariff Sheet No. F-2.00? 14

A. MGUC is adding language to specify the number of pricing pools that its billing 15

system can accommodate for the Choice Suppliers. The limitation is due to the 16

constraints of its third-party’s billing system which is not capable of expanding the 17

number of pricing pools available without substantial and costly modification. The 18

Company is also seeking to clarify that Choice Suppliers will be limited to adding no 19

more than two new pricing pools per month, once again due to the limitations 20

surrounding the processing of such requests by MGUC’s third-party billing partner, 21

Vertex Business Services (“Vertex”). 22

23

The Company has added language that defines the term “Pricing Category” and that 24

the Company shall issue Daily Delivery Obligations (“DDO’s”) for each of the delivery 25

pools associated with the Company’s five operating districts that have customers 26

enrolled by each Marketer under their various Pricing Categories. 27

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1

The Company has increased the period when it will provide DDO figures to the 2

Choice Suppliers from the closing day of bid trading to seven business days prior to 3

the end of the preceding month. This will provide more time to the Choice Suppliers 4

to secure their necessary supplies. 5

6


A. Language has been added to clarify that for each nominated quantity of gas a 8

Supplier intends to deliver, a corresponding nomination must be submitted for each 9

geographic delivery pool (MGUC’s five operating districts) associated with each of its 10

various pricing categories. 11

12

MGUC is also adding a provision for Gas-In-Kind volume retention to its Gas 13

Customer Choice Program. The Choice customers operate in a manner similar to 14

Transportation customers in that they deliver gas supplies into MGUC’s system. The 15

Gas-In-Kind retention percentage simply compensates the Company for moving that 16

gas on its system. 17

18

With regards to paragraph (12), the Buy/Sell provision, the Company has clarified 19

that remittance to the Supplier will take place 21 business days from the end of each 20

month, as opposed to calendar days. 21

22

Paragraph (13), the Annual Reconciliation provision, has been modified to include 23

retention of the Gas-In-Kind volumes specified in paragraph (10) above. 24

25


A. MGUC is incorporating the Gas-In-Kind volume retention provisions, specified on 27

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tariff sheet No. F-3.00, into its Annual Reconciliation. 1

2


A. MGUC has re-sequenced its paragraph numbers to accommodate the Gas-In-Kind 4

provision, specified on tariff sheet No. F-3.00. 5

6

Interim Rates 7 Q. Please provide an overview of the proposed interim rate design. 8

A. As authorized by MCL 460.6a(1), MGUC intends to self-implement interim rates for 9

service rendered on and after January 1, 2014. The interim increase is $ 8,036,820. 10

The proposed rate design is set forth in Schedule F6 of Exhibit A-6 (DJT-1). A 11

proposed tariff sheet is included in Schedule F5 of Exhibit A-6 (DJT-1). 12

13

Q. How did MGUC allocate the rate increase amongst the rate schedules? 14

A. MGUC’s interim rate increase was calculated in accordance with MCL 460.6a(1), 15

which requires an equal percentage increase across all rate schedules, based on 16

margin revenues. Lastly, neither the MGUC’s COSS nor the structural rate design 17

changes proposed for final rates were considered in the development and creation of 18

the proposed interim rate levels. 19

20

Q. In its 2010/2011 GCR Reconciliation proceeding in Case No. U-16145-R, the 21

Company was directed to conduct a feasibility study to determine whether 22

transferring to daily balancing will protect GCR customers. It was further 23

directed that this feasibility study, along with a proposal for transitioning to 24

daily balancing, shall be filed in the Company’s next rate case. Has the 25

Company conducted this study and is a proposal for transitioning to daily 26

balancing included in this filing? 27

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A. MGUC feels that daily balancing is an appropriate means to protect GCR customers 1

and to ensure that transportation customers will pay the costs related to the services 2

provided to them. However, at the present time, MGUC is not putting forth a 3

transition proposal to move toward daily balancing in this proceeding. 4

5

MGUC currently utilizes Vertex, a third-party provider, to perform its customer 6

billings. As mentioned in the pre-filed direct testimony of Mr. Brian E. Kage and 7

Michael E. Gerth, MGUC is moving forward on incorporating all its subsidiaries on a 8

consolidated billing system which will replace the billing functions performed by 9

Vertex. The consolidated billing system will incorporate daily balancing as part of its 10

design, but is not scheduled to be become operational until sometime in 2016. Since 11

the “ICE 2016” project is underway, it would not be prudent to have MGUC’s current 12

vendor develop a billing system to accommodate daily balancing only to have that 13

system replaced in a few more years. The cost of doing so would be prohibitive and 14

would not serve the customer’s interest. Therefore, MGUC has discussed delaying 15

the transition to daily balancing with Commission Staff until such time that the 16

transition to the new billing system is complete and informed Staff of its decision to 17

do so. 18

19


A. Yes, it does. 21

Schedule F2.1Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-6 (DJT-1)Summary of Present and Proposed Revenue by Rate Schedule Schedule: F2.1Including Cost of Gas Page: 1 of 1

Witness: D.J. Tyler

Current Proposed Revenue RevenueLine Revenue Revenue Increase IncreaseNo. MGUC Rate Schedule $ $ $ %

1 Residential $87,828,772 $91,340,095 $3,511,323 4.0%2 Multi-Family Class I 145,170 159,129 13,959 9.6%3 Multi-Family Class II 757,239 822,605 65,366 8.6%4 Multi-Family Class III 204,545 215,929 11,384 5.6%5 Multi-Family Class IV 290,242 308,883 18,641 6.4%6 General Service - Small 21,946,623 23,798,426 1,851,803 8.4%7 General Service - Large 1,883,202 1,898,009 14,807 0.8%8 Special Contract 125,361 125,361 0 0.0%9 TR-1 Transport 2,408,782 2,442,382 33,600 1.4%

10 TR-2 Transport 2,614,176 2,614,176 0 0.0%11 TR-3 Transport 1,683,099 1,683,099 0 0.0%12 Aggregated - Residential 14,249 15,438 1,188 8.3%13 Aggregated - General Service - Small 1,849,310 2,598,989 749,678 40.5%14 Aggregated - General Service - Large 42,425 42,242 (183) -0.4%15 Choice - Residential 7,422,614 8,055,531 632,917 8.5%16 Choice - General Service - Small 4,431,103 5,539,392 1,108,289 25.0%17 Choice - General Service - Large 0 0 0 0.0%18 Choice - Multi-Family - Class I 8,708 10,768 2,060 23.7%19 Choice - Multi-Family - Class II 33,385 38,931 5,545 16.6%20 Choice - Multi-Family - Class III 0 0 0 0.0%21 Choice - Multi-Family - Class IV 68,455 84,889 16,434 24.0%2223 TOTAL MGUC $133,757,461 $141,794,272 $8,036,811 6.0%2425 Note: Gas costs are included in both the Current Revenues or the Proposed Revenues above.

Schedule F2.2Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-6 (DJT-1)Summary of Present and Proposed Revenue by Rate Schedule Schedule: F2.2Excluding Cost of Gas Page: 1 of 1

Witness: D.J. Tyler

Current Proposed Revenue RevenueLine Revenue Revenue Increase IncreaseNo. MGUC Rate Schedule $ $ $ %

1 Residential $34,092,459 $37,603,782 $3,511,323 10.3%2 Multi-Family Class I 41,705 55,663 13,959 33.5%3 Multi-Family Class II 214,612 279,978 65,366 30.5%4 Multi-Family Class III 51,217 62,602 11,384 22.2%5 Multi-Family Class IV 67,007 85,648 18,641 27.8%6 General Service - Small 6,711,263 8,563,066 1,851,803 27.6%7 General Service - Large 388,399 403,206 14,807 3.8%8 Special Contract 123,770 123,770 0 0.0%9 TR-1 Transport 2,408,782 2,442,382 33,600 1.4%

10 TR-2 Transport 2,614,176 2,614,176 0 0.0%11 TR-3 Transport 1,683,099 1,683,099 0 0.0%12 Aggregated - Residential 14,249 15,438 1,188 8.3%13 Aggregated - General Service - Small 1,849,310 2,598,989 749,678 40.5%14 Aggregated - General Service - Large 42,425 42,242 (183) -0.4%15 Choice - Residential 7,422,614 8,055,531 632,917 8.5%16 Choice - General Service - Small 4,431,103 5,539,392 1,108,289 25.0%17 Choice - General Service - Large 0 0 0 0.0%18 Choice - Multi-Family - Class I 8,708 10,768 2,060 23.7%19 Choice - Multi-Family - Class II 33,385 38,931 5,545 16.6%20 Choice - Multi-Family - Class III 0 0 0 0.0%21 Choice - Multi-Family - Class IV 68,455 84,889 16,434 24.0%2223 TOTAL MGUC $62,266,739 $70,303,551 $8,036,811 12.9%2425 Note: No gas costs are included in either the Current Revenues or the Proposed Revenues above.

Schedule F3.1

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-6 (DJT-1)Present and Proposed Revenue Detail Including Cost of Gas Schedule: F3.1

Page: 1 of 10Witness: D.J. Tyler

(a) (c) (d) (e) (f)

LineNo. Description Quantity Units Rate Revenue Rate Revenue

1 Residential2 Monthly Customer Charge 1,500,968 Bills $11.00 $16,510,648 $12.00 $18,011,6163 Distribution Charge 10,997,567.2 Mcf 1.5987 17,581,811 1.7265 18,987,3004 Gas Supply Acquisition Charge 10,997,567.2 Mcf 0.0000 0 0.0550 604,8665 Cost of Gas 10,997,567.2 Mcf 4.8862 53,736,313 4.8862 53,736,3136 Total Residential $87,828,772 $91,340,09578 Notice Calculation9 Monthly Customer Charges 12 Bills $11.00 $132 $12.00 $14410 Distribution Charge 88.0 Mcf 1.5987 141 1.7265 15211 Gas Supply Acquisition Charge 88.0 Mcf 0.0000 0 0.0550 512 Cost of Gas 88.0 Mcf 4.8862 430 4.8862 43013 Total Annual Residential Bill $703 $7311415 Annual Residential Increase 4.0% $28.09

16 Monthly Residential Increase 4.0% $2.34

(b)

Billing Determinants Present Proposed

Schedule F3.1



(a) (c) (d) (e) (f)

Description Quantity Units Rate Revenue Rate Revenue

1 Multi-Family Class I2 Monthly Customer Charge 1,495 Bills $11.00 $16,445 $12.00 $17,9403 Distribution Charge 21,175.0 Mcf 1.1929 25,260 1.7265 36,5594 Gas Supply Acquisition Charge 21,175.0 Mcf 0.0000 0 0.0550 1,1655 Cost of Gas 21,175.0 Mcf 4.8862 103,465 4.8862 103,4656 Total $145,170 $159,12978 Multi-Family Class II9 Monthly Customer Charge 2,489 Bills $33.00 $82,137 $33.00 $82,13710 Distribution Charge 111,053.0 Mcf 1.1929 132,475 1.7265 191,73311 Gas Supply Acquisition Charge 111,053.0 Mcf 0.0000 0 0.0550 6,10812 Cost of Gas 111,053.0 Mcf 4.8862 542,627 4.8862 542,62713 Total $757,239 $822,6051415 Multi-Family Class III16 Monthly Customer Charge 203 Bills $88.00 $17,864 $33.00 $6,69917 Distribution Charge 31,379.7 Mcf 1.0629 33,353 1.7265 54,17718 Gas Supply Acquisition Charge 31,379.7 Mcf 0.0000 0 0.0550 1,72619 Cost of Gas 31,379.7 Mcf 4.8862 153,327 4.8862 153,32720 Total $204,545 $215,9292122 Multi-Family Class IV23 Monthly Customer Charge 129 Bills $143.00 $18,447 $33.00 $4,25724 Distribution Charge 45,686.8 Mcf 1.0629 48,560 1.7265 78,87825 Gas Supply Acquisition Charge 45,686.8 Mcf 0.0000 0 0.0550 2,51326 Cost of Gas 45,686.8 Mcf 4.8862 223,235 4.8862 223,23527 Total $290,242 $308,8832829 Total Multi-Family $1,397,197 $1,506,546

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 General Service - Small2 Monthly Customer Charge 91,160 Bills $33.00 $3,008,280 $33.00 $3,008,2803 Distribution Charge 3,118,038.6 Mcf 1.1876 3,702,983 1.7265 5,383,2944 Gas Supply Acquisition Charge 3,118,038.6 Mcf 0.0000 0 0.0550 171,4925 Cost of Gas 3,118,038.6 Mcf 4.8862 15,235,360 4.8862 15,235,3606 Total General Service - Small $21,946,623 $23,798,426

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 General Service - Large2 Monthly Customer Charge 199 Bills $400.00 $79,600 $400.00 $79,6003 Distribution Charge 305,923.4 Mcf 1.0094 308,799 1.0028 306,7804 Gas Supply Acquisition Charge 305,923.4 Mcf 0.0000 0 0.0550 16,8265 Cost of Gas 305,923.4 Mcf 4.8862 1,494,803 4.8862 1,494,8036 Total General Service - Large $1,883,202 $1,898,009

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 Special Contract2 Monthly Customer Charge 12 Bills $10,287.68 $123,452 $10,287.68 $123,4523 Distribution Charge 325.6 Mcf 0.9776 318 0.9776 3184 Gas Supply Acquisition Charge 325.6 Mcf 0.0000 0 0.0000 05 Cost of Gas 325.6 Mcf 4.8862 1,591 4.8862 1,5916 Total Special Contract $125,361 $125,361

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 TR-1 Transport2 Customer Charge 1,344 Bills $825.00 $1,108,800 $850.00 $1,142,4003 Distribution Charge - Peak 1,045,579.6 Mcf 0.7777 813,147 0.7777 813,1474 Off Peak 775,585.3 Mcf 0.6277 486,835 0.6277 486,8355 Total TR-1 Transport $2,408,782 $2,442,382

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 TR-2 Transport2 Customer Charge 468 Bills 2,250.00$ $1,053,000 2,250.00$ $1,053,0003 Distribution Charge - Peak 1,874,755.6 Mcf 0.4796 899,133 0.4796 899,1334 Off Peak 2,008,625.4 Mcf 0.3296 662,043 0.3296 662,0435 Total TR-2 Transport $2,614,176 $2,614,176

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 TR-3 Transport2 Customer Charge 84 Bills 3,050.00$ $256,200 3,050.00$ $256,2003 Distribution Charge - Peak 1,654,891.4 Mcf 0.4651 769,690 0.4651 769,6904 Off Peak 2,085,715.6 Mcf 0.3151 657,209 0.3151 657,2095 Total TR-3 Transport $1,683,099 $1,683,099

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 Aggregated - Residential2 Customer Charge 408 Bills 11.00$ $4,488 12.00$ $4,8963 Distribution Charge 6,105.8 Mcf 1.5987 9,761 1.7265 10,5424 Total $14,249 $15,43856 Aggregated - General Service - Small7 Customer Charge 5,976 Bills 33.00 $197,208 33.00 197,208$ 8 Distribution Charge 1,391,127.0 Mcf 1.1876 1,652,102 1.7265 2,401,7819 Total $1,849,310 $2,598,9891011 Aggregated - General Service - Large12 Customer Charge 36 Bills 400.00 $14,400 400.00 14,400$ 13 Distribution Charge 27,764.2 Mcf 1.0094 28,025 1.0028 27,84214 Total $42,425 $42,2421516 Total Aggregated $1,905,985 $2,656,668

(b)


Schedule F3.1



(a) (c) (d) (e) (f)


1 Choice - Residential2 Customer Charge 327,805 Bills 11.00$ $3,605,855 12.00$ $3,933,6603 Distribution Charge 2,387,414.3 Mcf 1.5987 3,816,759 1.7265 4,121,8714 Total $7,422,614 $8,055,53156 Choice - General Service - Small7 Customer Charge 60,264 Bills 33.00 $1,988,712 33.00 $1,988,7128 Distribution Charge 2,056,576.8 Mcf 1.1876 2,442,391 1.7265 3,550,6809 Total $4,431,103 $5,539,3921011 Choice - General Service - Large12 Customer Charge 0 Bills 400.00 $0 400.00 $013 Distribution Charge 0.0 Mcf 1.0094 0 1.0028 014 Total $0 $01516 Choice - Multi-Family - Class I17 Customer Charge 468 Bills 11.00$ $5,148 12.00$ $5,61618 Distribution Charge 2,984.0 Mcf 1.1929 3,560 1.7265 5,15219 Total $8,708 $10,7682021 Choice - Multi-Family - Class II22 Customer Charge 636 Bills 33.00 $20,988 33.00 $20,98823 Distribution Charge 10,392.5 Mcf 1.1929 12,397 1.7265 17,94324 Total $33,385 $38,9312526 Choice - Multi-Family - Class III27 Customer Charge 0 Bills 88.00 $0 33.00 $028 Distribution Charge 0.0 Mcf 1.0629 0 1.7265 029 Total $0 $03031 Choice - Multi-Family - Class IV32 Customer Charge 132 Bills 143.00 $18,876 33.00 $4,35633 Distribution Charge 46,645.3 Mcf 1.0629 49,579 1.7265 80,53334 Total $68,455 $84,8893536 Total Choice $11,964,265 $13,729,5103738 MGUC Totals39 Monthly Customer Charge 1,994,276 Bills $28,130,548 $29,955,41740 Distribution Charge 30,005,312.1 Mcf 34,136,191 39,543,43841 Gas Supply Acquisition Charge 14,631,149.3 Mcf 0 804,69542 Cost of Gas 14,631,149.3 Mcf 71,490,722 71,490,72243 Total MGUC $133,757,461 $141,794,272

(b)


Schedule F3.2

Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-6 (DJT-1)Present and Proposed Revenue Detail Excluding Cost of Gas Schedule: F3.2


(a) (c) (d) (e) (f)


1 Residential2 Monthly Customer Charge 1,500,968 Bills $11.00 $16,510,648 $12.00 $18,011,6163 Distribution Charge 10,997,567.2 Mcf 1.5987 17,581,811 1.7265 18,987,3004 Gas Supply Acquisition Charge 10,997,567.2 Mcf 0.0000 0 0.0550 604,8665 Cost of Gas 10,997,567.2 Mcf 0.0000 0 0.0000 06 Total Residential $34,092,459 $37,603,78278 Notice Calculation9 Monthly Customer Charges 12 Bills $11.00 $132 $12.00 $14410 Distribution Charge 88.0 Mcf 1.5987 141 1.7265 15211 Gas Supply Acquisition Charge 88.0 Mcf 0.0000 0 0.0550 512 Cost of Gas 88.0 Mcf 0.0000 0 0.0000 013 Total Annual Residential Bill $273 $3011415 Annual Residential Increase $28.09

16 Monthly Residential Increase $2.34

(b)


Schedule F3.2



(a) (c) (d) (e) (f)

Description Quantity Units Rate Revenue Rate Revenue

1 Multi-Family Class I2 Monthly Customer Charge 1,495 Bills $11.00 $16,445 $12.00 $17,9403 Distribution Charge 21,175.0 Mcf 1.1929 25,260 1.7265 36,5594 Gas Supply Acquisition Charge 21,175.0 Mcf 0.0000 0 0.0550 1,1655 Cost of Gas 21,175.0 Mcf 0.0000 0 0.0000 06 Total $41,705 $55,66378 Multi-Family Class II9 Monthly Customer Charge 2,489 Bills $33.00 $82,137 $33.00 $82,13710 Distribution Charge 111,053.0 Mcf 1.1929 132,475 1.7265 191,73311 Gas Supply Acquisition Charge 111,053.0 Mcf 0.0000 0 0.0550 6,10812 Cost of Gas 111,053.0 Mcf 0.0000 0 0.0000 013 Total $214,612 $279,9781415 Multi-Family Class III16 Monthly Customer Charge 203 Bills $88.00 $17,864 $33.00 $6,69917 Distribution Charge 31,379.7 Mcf 1.0629 33,353 1.7265 54,17718 Gas Supply Acquisition Charge 31,379.7 Mcf 0.0000 0 0.0550 1,72619 Cost of Gas 31,379.7 Mcf 0.0000 0 0.0000 020 Total $51,217 $62,6022122 Multi-Family Class IV23 Monthly Customer Charge 129 Bills $143.00 $18,447 $33.00 $4,25724 Distribution Charge 45,686.8 Mcf 1.0629 48,560 1.7265 78,87825 Gas Supply Acquisition Charge 45,686.8 Mcf 0.0000 0 0.0550 2,51326 Cost of Gas 45,686.8 Mcf 0.0000 0 0.0000 027 Total $67,007 $85,6482829 Total Multi-Family $374,542 $483,891

(b)


Schedule F3.2



(a) (c) (d) (e) (f)


1 General Service - Small2 Monthly Customer Charge 91,160 Bills $33.00 $3,008,280 $33.00 $3,008,2803 Distribution Charge 3,118,038.6 Mcf 1.1876 3,702,983 1.7265 5,383,2944 Gas Supply Acquisition Charge 3,118,038.6 Mcf 0.0000 0 0.0550 171,4925 Cost of Gas 3,118,038.6 Mcf 0.0000 0 0.0000 06 Total General Service - Small $6,711,263 $8,563,066

(b)


Schedule F3.2



(a) (c) (d) (e) (f)


1 General Service - Large2 Monthly Customer Charge 199 Bills $400.00 $79,600 $400.00 $79,6003 Distribution Charge 305,923.4 Mcf 1.0094 308,799 1.0028 306,7804 Gas Supply Acquisition Charge 305,923.4 Mcf 0.0000 0 0.0550 16,8265 Cost of Gas 305,923.4 Mcf 0.0000 0 0.0000 06 Total General Service - Large $388,399 $403,206

Present Proposed

(b)

Billing Determinants

Schedule F3.2



(a) (c) (d) (e) (f)


1 Special Contract2 Monthly Customer Charge 12 Bills $10,287.68 $123,452 $10,287.68 $123,4523 Distribution Charge 325.6 Mcf 0.9776 318 0.9776 3184 Gas Supply Acquisition Charge 325.6 Mcf 0.0000 0 0.0000 05 Cost of Gas 325.6 Mcf 0.0000 0 0.0000 06 Total Special Contract $123,770 $123,770

(b)


Schedule F3.2



(a) (c) (d) (e) (f)


1 TR-1 Transport2 Customer Charge 1,344 Bills $825.00 $1,108,800 $850.00 $1,142,4003 Distribution Charge - Peak 1,045,579.6 Mcf 0.7777 813,147 0.7777 813,1474 Off Peak 775,585.3 Mcf 0.6277 486,835 0.6277 486,8355 Total TR-1 Transport $2,408,782 $2,442,382

(b)


Schedule F3.2



(a) (c) (d) (e) (f)


1 TR-2 Transport2 Customer Charge 468 Bills 2,250.00$ $1,053,000 2,250.00$ $1,053,0003 Distribution Charge - Peak 1,874,755.6 Mcf 0.4796 899,133 0.4796 899,1334 Off Peak 2,008,625.4 Mcf 0.3296 662,043 0.3296 662,0435 Total TR-2 Transport $2,614,176 $2,614,176

(b)


Schedule F3.2



(a) (c) (d) (e) (f)


1 TR-3 Transport2 Customer Charge 84 Bills 3,050.00$ $256,200 3,050.00$ $256,2003 Distribution Charge - Peak 1,654,891.4 Mcf 0.4651 769,690 0.4651 769,6904 Off Peak 2,085,715.6 Mcf 0.3151 657,209 0.3151 657,2095 Total TR-3 Transport $1,683,099 $1,683,099

Present Proposed

(b)

Billing Determinants

Schedule F3.2



(a) (c) (d) (e) (f)


1 Aggregated - Residential2 Customer Charge 408 Bills 11.00$ $4,488 12.00$ $4,8963 Distribution Charge 6,105.8 Mcf 1.5987 9,761 1.7265 10,5424 Total $14,249 $15,43856 Aggregated - General Service - Small7 Customer Charge 5,976 Bills 33.00 $197,208 33.00 197,208$ 8 Distribution Charge 1,391,127.0 Mcf 1.1876 1,652,102 1.7265 2,401,7819 Total $1,849,310 $2,598,9891011 Aggregated - General Service - Large12 Customer Charge 36 Bills 400.00 $14,400 400.00 14,400$ 13 Distribution Charge 27,764.2 Mcf 1.0094 28,025 1.0028 27,84214 Total $42,425 $42,2421516 Total Aggregated $1,905,985 $2,656,668

(b)


Schedule F3.2



(a) (c) (d) (e) (f)


1 Choice - Residential2 Customer Charge 327,805 Bills 11.00$ $3,605,855 12.00$ $3,933,6603 Distribution Charge 2,387,414.3 Mcf 1.5987 3,816,759 1.7265 4,121,8714 Total $7,422,614 $8,055,53156 Choice - General Service - Small7 Customer Charge 60,264 Bills 33.00 $1,988,712 33.00 $1,988,7128 Distribution Charge 2,056,576.8 Mcf 1.1876 2,442,391 1.7265 3,550,6809 Total $4,431,103 $5,539,3921011 Choice - General Service - Large12 Customer Charge 0 Bills 400.00 $0 400.00 $013 Distribution Charge 0.0 Mcf 1.0094 0 1.0028 014 Total $0 $01516 Choice - Multi-Family - Class I17 Customer Charge 468 Bills 11.00$ $5,148 12.00$ $5,61618 Distribution Charge 2,984.0 Mcf 1.1929 3,560 1.7265 5,15219 Total $8,708 $10,7682021 Choice - Multi-Family - Class II22 Customer Charge 636 Bills 33.00 $20,988 33.00 $20,98823 Distribution Charge 10,392.5 Mcf 1.1929 12,397 1.7265 17,94324 Total $33,385 $38,9312526 Choice - Multi-Family - Class III27 Customer Charge 0 Bills 88.00 $0 33.00 $028 Distribution Charge 0.0 Mcf 1.0629 0 1.7265 029 Total $0 $03031 Choice - Multi-Family - Class IV32 Customer Charge 132 Bills 143.00 $18,876 33.00 $4,35633 Distribution Charge 46,645.3 Mcf 1.0629 49,579 1.7265 80,53334 Total $68,455 $84,8893536 Total Choice $11,964,265 $13,729,5103738 MGUC Totals39 Monthly Customer Charge 1,994,276 Bills $28,130,548 $29,955,41740 Distribution Charge 30,005,312.1 Mcf 34,136,191 39,543,43841 Gas Supply Acquisition Charge 14,631,149.3 Mcf 0 804,69542 Cost of Gas 14,631,149.3 Mcf 0 043 Total MGUC $62,266,739 $70,303,551

(b)


Schedule F4Michigan Public Service Commission Case No.: U-17273Michigan Gas Utilities Corporation Exhibit No.: A-6 (DJT-1)Comparison of Present and Proposed Monthly Bills Schedule: F4

Page: 1 of 8RESIDENTIAL Service Rate Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f)

Line Monthly Present Net Proposed Net UnitNo. Usage Monthly Bill Monthly Bill Amount Percent Cost

(Mcf) ($/Month) ($/Month) ($/Month) (%) ($/Mcf)

1 0 $11.00 $12.00 $1.00 9.09%2 2 23.97 25.34 1.37 5.70% $12.673 5 43.42 45.34 1.91 4.41% 9.074 7 56.39 58.67 2.28 4.04% 8.385 10 75.85 78.68 2.83 3.73% 7.876 15 108.27 112.02 3.74 3.46% 7.477 20 140.70 145.35 4.66 3.31% 7.278 25 173.12 178.69 5.57 3.22% 7.159 30 205.55 212.03 6.48 3.15% 7.07

Increase


Page: 2 of 8MULTI-FAMILY Service Rate Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f) (g)

Monthly Present Net Proposed Net Increase UnitLine Meter Usage Monthly Bill Monthly Bill Amount Percent CostNo. Class (Mcf) ($/Month) ($/Month) ($/Month) (%) ($/Mcf)

1 Multi-Family Class I 0 $11.00 $12.00 $1.00 9.09%2 Multi-Family Class I 5 41.40 45.34 3.94 9.53% $9.073 Multi-Family Class I 10 71.79 78.68 6.89 9.59% 7.874 Multi-Family Class I 20 132.58 145.35 12.77 9.63% 7.275 Multi-Family Class I 35 223.77 245.37 21.60 9.65% 7.0167 Multi-Family Class II 0 33.00 33.00 0.00 0.00%8 Multi-Family Class II 10 93.79 99.68 5.89 6.28% 9.979 Multi-Family Class II 25 184.98 199.69 14.72 7.96% 7.9910 Multi-Family Class II 50 336.96 366.39 29.43 8.73% 7.3311 Multi-Family Class II 100 640.91 699.77 58.86 9.18% 7.001213 Multi-Family Class III 0 88.00 33.00 (55.00) -62.50%14 Multi-Family Class III 25 236.73 199.69 (37.04) -15.64% 7.9915 Multi-Family Class III 50 385.46 366.39 (19.07) -4.95% 7.3316 Multi-Family Class III 100 682.91 699.77 16.86 2.47% 7.0017 Multi-Family Class III 200 1,277.82 1,366.54 88.72 6.94% 6.8318 Multi-Family Class III 250 1,575.28 1,699.93 124.65 7.91% 6.801920 Multi-Family Class IV 0 143.00 33.00 (110.00) -76.92%21 Multi-Family Class IV 25 291.73 199.69 (92.04) -31.55% 7.9922 Multi-Family Class IV 50 440.46 366.39 (74.07) -16.82% 7.3323 Multi-Family Class IV 100 737.91 699.77 (38.14) -5.17% 7.0024 Multi-Family Class IV 200 1,332.82 1,366.54 33.72 2.53% 6.8325 Multi-Family Class IV 250 1,630.28 1,699.93 69.65 4.27% 6.80


Page: 3 of 8SMALL GENERAL SERVICE Rate Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f)



1 0 $33.00 $33.00 $0.00 0.00%2 10 93.74 99.68 5.94 6.34% $9.973 25 184.85 199.69 14.85 8.03% 7.994 50 336.69 366.39 29.70 8.82% 7.335 75 488.54 533.08 44.54 9.12% 7.116 100 640.38 699.77 59.39 9.27% 7.00

Increase


Page: 4 of 8LARGE GENERAL SERVICE Rate Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f)



1 0 $400.00 $400.00 $0.00 0.00%2 10 458.96 459.44 0.48 0.11% $45.943 50 694.78 697.20 2.42 0.35% 13.944 100 989.56 994.40 4.84 0.49% 9.945 250 1,873.90 1,886.00 12.10 0.65% 7.546 500 3,347.80 3,372.00 24.20 0.72% 6.747 750 4,821.70 4,858.00 36.30 0.75% 6.488 1,000 6,295.60 6,344.00 48.40 0.77% 6.349 1,250 7,769.50 7,830.00 60.50 0.78% 6.2610 1,500 9,243.40 9,316.00 72.60 0.79% 6.21

Increase


Page: 5 of 8TRANSPORT Service Rate Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f) (g)


1 TR-1 Transport 0 825.00 850.00 $25.00 3.03%2 TR-1 Transport 500 1,181.91 1,206.91 25.00 2.12% $2.413 TR-1 Transport 1,000 1,538.82 1,563.82 25.00 1.62% 1.564 TR-1 Transport 2,000 2,252.64 2,277.64 25.00 1.11% 1.145 TR-1 Transport 3,000 2,966.46 2,991.46 25.00 0.84% 1.0067 TR-2 Transport 0 2,250.00 2,250.00 0.00 0.00%8 TR-2 Transport 1,000 2,652.01 2,652.01 0.00 0.00% 2.659 TR-2 Transport 2,500 3,255.04 3,255.04 0.00 0.00% 1.3010 TR-2 Transport 5,000 4,260.07 4,260.07 0.00 0.00% 0.8511 TR-2 Transport 10,000 6,270.15 6,270.15 0.00 0.00% 0.631213 TR-3 Transport 0 3,050.00 3,050.00 0.00 0.00%14 TR-3 Transport 2,500 4,003.65 4,003.65 0.00 0.00% 1.6015 TR-3 Transport 5,000 4,957.31 4,957.31 0.00 0.00% 0.9916 TR-3 Transport 10,000 6,864.62 6,864.62 0.00 0.00% 0.6917 TR-3 Transport 25,000 12,586.55 12,586.55 0.00 0.00% 0.5018 TR-3 Transport 50,000 22,123.09 22,123.09 0.00 0.00% 0.4419 TR-3 Transport 75,000 31,659.64 31,659.64 0.00 0.00% 0.42


Page: 6 of 8AGGREGATED TRANSPORT Service Rate Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f) (g)


1 Aggregated - Residential 0 $11.00 $12.00 $1.00 9.09%2 Aggregated - Residential 2 14.20 15.45 1.26 8.84% $7.733 Aggregated - Residential 5 18.99 20.63 1.64 8.63% 4.134 Aggregated - Residential 7 22.19 24.09 1.89 8.54% 3.445 Aggregated - Residential 10 26.99 29.27 2.28 8.44% 2.936 Aggregated - Residential 15 34.98 37.90 2.92 8.34% 2.537 Aggregated - Residential 20 42.97 46.53 3.56 8.27% 2.338 Aggregated - Residential 25 50.97 55.16 4.20 8.23% 2.219 Aggregated - Residential 30 58.96 63.80 4.83 8.20% 2.131011 Aggregated - General Service - Small 0 33.00 33.00 0.00 0.00%12 Aggregated - General Service - Small 10 44.88 50.27 5.39 12.01% 5.0313 Aggregated - General Service - Small 25 62.69 76.16 13.47 21.49% 3.0514 Aggregated - General Service - Small 50 92.38 119.33 26.95 29.17% 2.3915 Aggregated - General Service - Small 75 122.07 162.49 40.42 33.11% 2.1716 Aggregated - General Service - Small 100 151.76 205.65 53.89 35.51% 2.061718 Aggregated - General Service - Large 0 400.00 400.00 0.00 0.00%19 Aggregated - General Service - Large 10 410.09 410.03 (0.07) -0.02% 41.0020 Aggregated - General Service - Large 50 450.47 450.14 (0.33) -0.07% 9.0021 Aggregated - General Service - Large 100 500.94 500.28 (0.66) -0.13% 5.0022 Aggregated - General Service - Large 250 652.35 650.70 (1.65) -0.25% 2.6023 Aggregated - General Service - Large 500 904.70 901.40 (3.30) -0.36% 1.8024 Aggregated - General Service - Large 750 1,157.05 1,152.10 (4.95) -0.43% 1.5425 Aggregated - General Service - Large 1,000 1,409.40 1,402.80 (6.60) -0.47% 1.4026 Aggregated - General Service - Large 1,250 1,661.75 1,653.50 (8.25) -0.50% 1.3227 Aggregated - General Service - Large 1,500 1,914.10 1,904.20 (9.90) -0.52% 1.27


Page: 7 of 8CHOICE Service Rates Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f) (g)


1 Choice - Residential 0 $11.00 $12.00 $1.00 9.09%2 Choice - Residential 2 14.20 15.45 1.26 8.84% $7.733 Choice - Residential 5 18.99 20.63 1.64 8.63% 4.134 Choice - Residential 7 22.19 24.09 1.89 8.54% 3.445 Choice - Residential 10 26.99 29.27 2.28 8.44% 2.936 Choice - Residential 15 34.98 37.90 2.92 8.34% 2.537 Choice - Residential 20 42.97 46.53 3.56 8.27% 2.338 Choice - Residential 25 50.97 55.16 4.20 8.23% 2.219 Choice - Residential 30 58.96 63.80 4.83 8.20% 2.131011 Choice - General Service - Small 0 33.00 33.00 0.00 0.00%12 Choice - General Service - Small 10 44.88 50.27 5.39 12.01% 5.0313 Choice - General Service - Small 25 62.69 76.16 13.47 21.49% 3.0514 Choice - General Service - Small 50 92.38 119.33 26.95 29.17% 2.3915 Choice - General Service - Small 75 122.07 162.49 40.42 33.11% 2.1716 Choice - General Service - Small 100 151.76 205.65 53.89 35.51% 2.061718 Choice - General Service - Large 0 400.00 400.00 0.00 0.00%19 Choice - General Service - Large 10 410.09 410.03 (0.07) -0.02% 41.0020 Choice - General Service - Large 50 450.47 450.14 (0.33) -0.07% 9.0021 Choice - General Service - Large 100 500.94 500.28 (0.66) -0.13% 5.0022 Choice - General Service - Large 250 652.35 650.70 (1.65) -0.25% 2.6023 Choice - General Service - Large 500 904.70 901.40 (3.30) -0.36% 1.8024 Choice - General Service - Large 750 1,157.05 1,152.10 (4.95) -0.43% 1.5425 Choice - General Service - Large 1,000 1,409.40 1,402.80 (6.60) -0.47% 1.4026 Choice - General Service - Large 1,250 1,661.75 1,653.50 (8.25) -0.50% 1.3227 Choice - General Service - Large 1,500 1,914.10 1,904.20 (9.90) -0.52% 1.27


Page: 8 of 8CHOICE Service Rate Witness: D.J. Tyler

(a) (b) (c) (d) (e) (f) (g)


1 Choice - Multi-Family - Class I 0 $11.00 $12.00 1.00 9.09%2 Choice - Multi-Family - Class I 5 16.96 20.63 3.67 21.62% $4.133 Choice - Multi-Family - Class I 10 22.93 29.27 6.34 27.63% 2.934 Choice - Multi-Family - Class I 20 34.86 46.53 11.67 33.48% 2.335 Choice - Multi-Family - Class I 35 52.75 72.43 19.68 37.30% 2.0767 Choice - Multi-Family - Class II 0 33.00 33.00 $0.00 0.00%8 Choice - Multi-Family - Class II 10 44.93 50.27 5.34 11.88% 5.039 Choice - Multi-Family - Class II 25 62.82 76.16 13.34 21.23% 3.0510 Choice - Multi-Family - Class II 50 92.65 119.33 26.68 28.80% 2.3911 Choice - Multi-Family - Class II 100 152.29 205.65 53.36 35.04% 2.061213 Choice - Multi-Family - Class III 0 88.00 33.00 (55.00) -62.50%14 Choice - Multi-Family - Class III 25 114.57 76.16 (38.41) -33.52% 3.0515 Choice - Multi-Family - Class III 50 141.15 119.33 (21.82) -15.46% 2.3916 Choice - Multi-Family - Class III 100 194.29 205.65 11.36 5.85% 2.0617 Choice - Multi-Family - Class III 200 300.58 378.30 77.72 25.86% 1.8918 Choice - Multi-Family - Class III 250 353.73 464.63 110.90 31.35% 1.861920 Choice - Multi-Family - Class IV 0 143.00 33.00 (110.00) -76.92%21 Choice - Multi-Family - Class IV 25 169.57 76.16 (93.41) -55.09% 3.0522 Choice - Multi-Family - Class IV 50 196.15 119.33 (76.82) -39.16% 2.3923 Choice - Multi-Family - Class IV 100 249.29 205.65 (43.64) -17.51% 2.0624 Choice - Multi-Family - Class IV 200 355.58 378.30 22.72 6.39% 1.8925 Choice - Multi-Family - Class IV 250 408.73 464.63 55.90 13.68% 1.86

Case No. U-17273 Witness: David J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 1 of 24


SUMMARY OF TARIFF CHANGES Tariff Sheet No. Rule No. Paragraph Description of Changes C-23.00 C5.3 Selection of A requirement has been added that a Rate customer’s account must be “current” in order to switch rates or services.

C-24.00 C5.6 Meter Reading Language added to clarify the term “month” as and Billing used for purposes of billing. Periods C-34.00 C11 Payment of Language updated to reflect change in

Customer operating practices. Contribution C-35.00 C11 Connection Fee Language added to clarify fees for multiple

metered installations. D-1.00 D2 Supplemental Provides for Interim Rate Surcharges. Charges D-1.02 D2 Supplemental Moved the EO Surcharge for purposes of Charges tariff organization. D–6.00 D4 Rate New designation added for a Daily Customer

charge. The Customer and Distribution Charges have been updated per the proposed rate design.

D-7.00 D5 Availability & The Multi-Family Dwelling Rate is being

Definitions consolidated under Residential and Small General Services. D-8.00 D5 (all) The Multi-Family Dwelling Rate is being

consolidated under Residential and Small General Services.

D-9.00 D5 (all) The Multi-Family Dwelling Rate is being




SUMMARY OF TARIFF CHANGES Tariff Sheet No. Rule No. Paragraph Description of Changes D-10.00 D5 (all) The Multi-Family Dwelling Rate is being


D–11.00 D6 Rate New designation added for a Daily Customer


D–13.00 D7 Rate New designation added for a Daily Customer


D-15.00 D8 Availability The Distribution Charges have been updated

per the proposed rate design. E-13.00 E5.4 Rates The Monthly Customer charges and

Transportation Rates been revised per the proposed rate design.

E-14.00 E5.7 Gas In Kind The Gas-In-Kind percentage has been

updated for the most recent 5-Year average. E-17.00 E5.10 Authorized Expanded the restrictions on storage

Tolerance Level injections to include November. Restrictions F-2.00 F1.1 General Provisions Language has been added to clarify the

number of pricing pools available and to define the term “Pricing Category”.

Language has been added to clarify that

DDO’s will be issued for each delivery pool behind the Company’s five operating districts associated with a Pricing Category.

The time frame for issuing first of the month

DDO’s has been updated.



SUMMARY OF TARIFF CHANGES Tariff Sheet No. Rule No. Paragraph Description of Changes F-3.00 F1.1 General Provisions Language has been added to clarify that

nominations shall be required for each Pricing Category and associated geographic delivery pool.

A provision has been added for the retention

of Gas-In-Kind applicable to Choice supplies. The potage rate for customer billings has

been updated. F-4.00 F1.1 General Provisions The Gas-In-Kind provisions have been

incorporated into the Annual Reconciliation. F-5.00 F1.1 General Provisions Numeric sequencing has been updated to

reflect insertion of the new provision for Gas In Kind.

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 4 of 24 MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. C-23.00 M.P.S.C. No. 2 – GAS Replaces First Revised Sheet No. C-23.00

Continued From Sheet No. C-22.00

C5.3 Liability. (Contd)

(c) Selection of rate.

The Company will endeavor to assist a customer in the selection of the filed rate which may be most favorable to his requirements, but the responsibility for the selection of the rate lies with the customer and the Company makes no warranty, expressed or implied, as to the rates, classifications or provisions favorable to the future service requirements of the customer.

After the customer has selected the rate under which the customer elects to take service, the customer shall not be permitted to change from that rate to another rate until at least 12 months have elapsed. The customer shall not be permitted to evade this rule by temporarily terminating service. However, the Company may, at its option, waive the provisions of this paragraph where it appears that an earlier change is requested for permanent rather than for temporary or seasonal advantage. The effective date of a rate change under this rule shall be the beginning read date of the next bill issued. The intent of this rule is to prohibit frequent shifts from rate to rate. If a customer is in arrears with the Company, the customer is not eligible to switch rate classifications until arrearages have been paid in full or the Company grants a waiver.

C5.4 Service charge for reconnection of discontinued service For Non-Payment of

Bills (other than theft or tampering).

A charge of $40.00 will be collected by the Company to offset the cost of restoring service during regular working hours to any customer whose previous service has been discontinued for nonpayment of bills or for any other breach by the customer of the Company's Rates, Rules and Regulations. If the customer specifically requests restoration of service after regular working hours and the customer is advised of the increased charge, a restoration charge of $75.00 shall be collected. This charge shall become part of the customer's arrears and will be subject to the same payment requirements applicable thereto.

C5.5 Deposits.

A reasonable cash deposit may be required of Residential customers according to Rules 9 and 10 (R460.109 and R460.110) and of Commercial customers according to Rule 13 (R460.2083), unless waived by the Company upon evidence of satisfactory credit in the opinion of the Company or if the account is guaranteed by a responsible party in lieu of deposit. Such guarantee must be in writing and specify maximum amount guaranteed by guarantor. If the customer refuses or fails to pay the required deposit or furnish a guarantor, the Company may withhold its service or discontinue its service. Interest on deposits from Residential customers shall accrue at the rate of seven percent (7%) per annum and shall be credited semi-annually or upon return of the deposit, whichever occurs first. Interest on deposits for Commercial

Continued on Sheet No. C-24.00 Issued: Effective for Service By J F Schott On and After: VP Regulatory Affairs Issued Under Authority of

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 5 of 24

MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. C-24.00 M.P.S.C. No. 2 – GAS Replaces First Revised Sheet No. C-24.00

Continued from Sheet No. C-23.00 C5.5 Deposits. (contd.)

customers shall accrue at the rate of seven percent (7%) per annum and shall be credited semi-annually or upon return of the deposit, provided that such deposit is held at least six (6) months.

C5.6 Meter Reading and Billing Periods.

Bills shall be rendered once each month as nearly as is possible on a normal monthly period. The term “month” for billing purposes will mean the period between any two consecutive readings to be taken as nearly practicable every 30 days. Reasonable efforts will be made to read the customer's meter at least once in two months on or about the same day of such meter reading month. When, for any reason, an actual meter reading is not obtained, the bill will be estimated on the basis of past service records, adjusted for seasonal variations. When past records are not available, billing will be based upon whatever other data are available. Each account shall be adjusted as necessary each time an actual meter reading is obtained. Bills rendered for gas service for periods when actual meter readings were not obtained, shall have the same force and effect as those based on actual meter readings. Where the Company renders a bill for an elapsed period other than a regular billing period, the rates and charges will be prorated except that a customer who terminates service less than 28 days after the commencement of service will be billed for a month.

C5.7 Payment of Bills.

Bills for gas service furnished by the Company are due 21 days for residential customers and 21 days for non-residential customers from the date the bill is mailed (otherwise specified). Bills of the Company for service are payable at any District Customer Service Office or to a duly authorized “Payment Station” of the Company. Payment Stations are authorized to collect a fee from the customer for accepting payments.

C5.8 Delinquent Bills.

If any bill for gas service remains unpaid for a period of 26 days after it is rendered the Company shall have the right to discontinue such service upon ten days notice in writing of its intentions to so discontinue, and such discontinuance of service may be in effect until such bill has been paid.

C5.9 Charge for Nonsufficient Funds (NSF) Check.

A charge of $20.00 will be levied upon a customer for each check the customer issues the Company in payment for a gas bill when the check is returned to the Company marked NSF or closed account by the financial institution upon which the check is drawn. This charge will become part of the customer's arrears and will be subject to the same requirements applicable thereto.

Continued on Sheet No. C-25.00 Issued: Effective for Service

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 6 of 24

MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. C-34.00 M.P.S.C. No. 2 – GAS Replaces First Revised Sheet No. C-34.00

Continued from Sheet No. C-33.00 C11. CUSTOMER ATTACHMENT PROGRAM

(1) Purpose

The Company proposes to make extension of its gas mains and/or service lines from time to time, at its own cost, to serve applicants whose requirements will not disturb or impair the service to prior users or will not require an expenditure out of proportion to the revenue obtainable there from.

The Company reserves the right to delay or deny a request for service under this rule, if fulfilling such a request could, in the Company's opinion, create conditions potentially adverse to the Company or its customers. Such conditions may include, but are not limited to, safety issues, system operating requirements or capital constraints. The provisions under this Rule are in addition to the existing rules and tariffs for customer gas service.

(2) Customer Contribution

A Customer Contribution shall be required equal to the Connection Fee plus any applicable Fixed Monthly Surcharge plus any Excessive Service Line Fee. The Connection Fee is not considered in the CAP model when calculating the Fixed Monthly Surcharge or Excessive Service Line Fee.

(3) Payment of Customer Contribution

For all customers other than land developers and builders the Customer Contribution shall be paid as follows:

The Connection Fee and the Excessive Service Line Fee are payable in lump sum at the time the service agreement is executed by the customer. The Connection Fee is non-refundable. The Excessive Service Line Fee is refundable if the service line has not been installed. If the service line has been installed, the Excessive Service Line Fee is non-refundable. The Fixed Monthly Surcharge shall be payable monthly throughout the surcharge period. The Fixed Monthly Surcharge will commence on the date that the customer receives gas service Company installs the meter. The customer may at any time elect to pay off the remaining Fixed Monthly Surcharge balance with a lump sum payment equal to the present value of the remaining monthly payments. If the present value of the Fixed Monthly Surcharge is less than $200.00, the Company may require the customer to make a lump sum payment. The Fixed Monthly Surcharge is assessed to the property served such that any subsequent customer requesting gas service at the property address, once notified by the Company of the amount and duration of such surcharge, shall be liable for the Fixed Monthly Surcharge. Such notification may be verbal, written or in the form of a bill which includes the Fixed Monthly Surcharge. Failure of sellers, agents, lessors or other non-company parties to notify a customer of the Fixed Monthly Surcharge shall not relieve the customer's obligation to pay the Fixed Monthly Surcharge. Failure by the customer to timely pay the Fixed Monthly Surcharge shall result in the discontinuation, termination or denial of natural gas service.

Continued on Sheet No. C-35.00 Issued: Effective for Service By J F Schott On and After: VP Regulatory Affairs Issued Under Authority of

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 7 of 24 MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. C-35.00 M.P.S.C. No. 2 – GAS Replaces First Revised No. C-35.00

Continued from Sheet No. C-34.00 C11. Customer Attachment Program (Contd)

(3) Payment of Customer Contribution (Contd) For land developers and builders, the Customer Contribution shall be required in a lump sum in advance of the facility expansion.

(4) Connection Fee

The Connection Fee is equal to $200.00. The Connection Fee is not considered in the CAP Model when calculating the Fixed Monthly Surcharge or Excessive Service Line Fee.

For customers requesting a multiple metered installation, the Connection Fee shall be $100 for each additionalper account.

(5) Excessive Service Line Fee

The Excessive Service Line Fee will be assessed to a customer whose service line requirement is in excess of the Service Line Limit. The Service Line Limit for an individual service line shall be equal to the point at which the cost of the customer’s service requirements are greater than the allowance based on the Cost Of Service Model. The Company reserves the right to use a different Service Line Limit for different categories of customers. In calculating the average service line length for a project containing more than one customer, the maximum length of each service line to be included in the calculation is the Service Line Limit for a primary residential home. The Company, in its sole discretion, may waive the excessive service line fee or extend the service line limit for all attaching parties based on the economics of a proposed project. Any such waiver or extension shall not be effective unless provided in writing by the Company.

(6) Fixed Monthly Surcharge

A Fixed Monthly Surcharge (Surcharge) will be calculated for each Customer Attachment Project (Project). The Surcharge will recover the Revenue Deficiency anticipated from the proposed Project. The Surcharge is calculated such that the present value of the anticipated Surcharges collected from the Project will equal the net present value Revenue Deficiency. The Surcharge will be recoverable over a predetermined time period, not to exceed ten years. The Company will be responsible for determining the appropriate Surcharge time period. The Surcharge will be a fixed dollar amount for all customers within the Project and will expire on the same date for all customers within the Project, regardless of when the surcharge was initially assessed to the customer. The Surcharge will not be subject to adjustment, reconciliation or refund. A customer who attaches to a Project after the surcharge period has expired or a customer whose proposed attachment was beyond the scope of the original a Project, will be treated as a separate Project.

Continued on Sheet No. C-36.00

Issued: Effective for Service By J F Schott On and After: VP Regulatory Affairs Issued Under Authority of

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 8 of 24 MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. D-1.00 M.P.S.C. No. 2 – GAS Replaces First Revised Sheet No. D-1.00

SECTION D

RATE SCHEDULES D1. GENERAL TERMS AND CONDITIONS OF THE TARIFF

(1) Controlled service.

All rates are subject to all provisions in Rule C2. of the Rules and Regulations of the Company which are applicable to priority of service hereunder.

(2) Territory served.

All rates apply in the territory served by the Company, comprising the cities, villages and townships in all Districts in the applicable Rules and Regulations of the Company except where specifically noted.

D2. SUPPLEMENTAL CHARGES

Each Rate Schedule may be subject to supplemental charges under Rule C11, Customer Attachment Program, a Reservation Charge, Interim Rate Increase, Uncollectible Expense Tracking Mechanism (“UETM”), Revenue Decoupling Mechanism and Energy Optimization (“EO”) surcharges required by Public Act 295, as detailed below: RESERVATION CHARGE – This charge allows for the recovery of costs related to the assets necessary to provide peak-day coverage and for the utility to serve as the “supplier of last resort” for Gas Customer Choice program customers, as required by the Commission in Case No. U-15929. The Reservation Charge as also a base component of the GCR factor, which also is comprised of a Commodity Charge. Reservation Charge $0.6448 per Mcf INTERIM RATE INCREASE SURCHARGE:

Customer Class Interim Surcharge Residential $ 0.4011 per Mcf Multi-Family $ 0.2329 per Mcf Small General Service $ 0.2559 per Mcf Large General Service $ 0.1670 per Mcf Transportation - TR-1 $ 0.1711 per Mcf TR-2 $ 0.0871 per Mcf TR-3 $ 0.0582 per Mcf

Continued on Sheet No. D-1.01 Issued: Effective for Service

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 9 of 24 MICHIGAN GAS UTILITIES CORPORATION First Revised Sheet No. D-1.02 M.P.S.C. No. 2 – GAS Replaces Original Sheet No. D-1.02

Continued from Sheet No. D-1.01 SECTION D

RATE SCHEDULES

D2. SUPPLEMENTAL CHARGES (contd.)

REVENUE DECOUPLING MECHANISM (2011) Customer bills shall be adjusted by the decoupling surcharge or credit, per Mcf, effective September 1, 2012 through August 31, 2013, on a service rendered basis.

Rate Schedule Adjustment/Mcf Residential General and Heating ($ 0.04603) (including Transport and Choice)

Multi-Family, Class I and II $ 0.13044 (including Transport and Choice) Small General Service General and Heating $ 0.13044

(including Transport and Choice)

Multi-Family, Class III and IV $ 0.00174 (including Transport and Choice)

ENERGY OPTIMIZATION Surcharge – this charge permits, pursuant to Section 91(4) of 2008 PA 295, the adjustment of rates, to allow for recovery of the payments made by the Company in compliance with Section 91(1) of 2008 PA 295.

Customer Class EO Surcharge Residential $ 0.1811 per Mcf Multi-Family $ 0.1811 per Mcf Small General Service $ 4.17 per meter, per month Large General Service $ 215.45 per meter, per month Commercial Lighting $ 10.33 per contract, per month Special Contracts $ 221.26 per month Transportation - TR-1 $ 39.27 per meter, per month TR-2 $ 119.34 per meter, per month TR-3 $ 408.71 per meter, per month

Continued on Sheet No. D-2.00 Issued: Effective for Service By: J. F. Schott On and After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission Order Dated:

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 10 of 24 MICHIGAN GAS UTILITIES CORPORATION Fourth Revised Sheet No. D-6.00 M.P.S.C. No. 2 – GAS Replaces Third Revised Sheet No. D-6.00

Continued From Sheet No. D-5.00 D4. RESIDENTIAL RATE - (General and Heating) (Contd)

RATE

Customer Charge: Daily Monthly

$ 0.3945 per customer, plus $ 12.00 per customer, plus

Distribution Charge $1.7815 per Mcf, plus

Gas Cost Recovery Charge The monthly gas cost recovery charge as set forth on Sheet No. D-2.00.

Supplemental Charges

This rate is subject to the Supplemental Charges set forth on Sheet Nos. D-1.00, D-1.01 and D-1.02.

Seasonal Service Charge

A charge of $45.00 payable in either a flat amount or three equal installments, will be made to partially cover the cost of restoring service when it has been temporarily discontinued at the customer's request.

Late Payment Charge and Due Date

A late payment charge of 2%, not compounded, net of sales tax, will be added to any bill which is delinquent. Customers participating in the Winter Protection Plan will not be assessed the late payment charge. The due date shall be 21 days following the date of mailing.

GAS ALLOCATION PROCEDURE

This rate schedule is subject to the provisions of Rule C2.7. SPECIAL TAXES

(1) In municipalities which levy special taxes, license fees, or street rentals against

the Company, and which levy has been successfully maintained, the standard of rates shall be increased within the limits of such municipalities so as to offset such special charges and thereby prevent the customers in other localities from being compelled to share any portion of such local increase.

Continued on Sheet No. D-7.00 Issued: Effective for Service By: J. F. Schott On and After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission


Continued From Sheet No. D-6.00 D4. RESIDENTIAL RATE - (General and Heating) (Contd)

(2) Bills shall be increased to offset any new or increased specific tax or excise imposed by any governmental authority upon the Company's production, transmission or sale of gas.

RULES AND REGULATIONS Service under this rate schedule shall be subject to the Standard Rules and Regulations of the Company.

D5. RESIDENTIAL MULTIPLE FAMILY DWELLING RATE - (General and Heating)

AVAILABILITY

Subject to limitations and restrictions contained in orders of the Michigan Public Service Commission in effect from time to time and in the Standard Rules and Regulations of the Company, service is available under this rate schedule to any of the Company's existing multiple family dwelling customers as of January 5, l978, for any centrally metered installations containing individual households for residential service. This rate is not available for commercial or industrial service, including swimming pool heater usage.

Any swimming pool heater usage or other commercial type usage shall be Company submetered or separately metered in order for the customer to remain on this rate schedule. The Company shall furnish the required meter and install it at the customer's expense.

DEFINITIONS

As used in this rate schedule, "residential service" means service to any multiple family dwelling customer for purposes of space heating and other domestic uses. A multiple family dwelling includes such living facilities as, for example, cooperatives, condominiums and apartments; provided, however, in order to qualify for this service, each household within such multiple family dwelling must have the normal household facilities such as bathroom, individual cooking and kitchen sink. A "multiple family dwelling" does not include such living facilities as, for example, penal or corrective institution, motels, hotels, dormitories, nursing homes, tourist homes, military barracks, hospitals, special care facilities or any other facilities primarily associated with the purchase, sale or supplying (for profit or otherwise) of a commodity, product or service by a public or private person, entity, organization or institution; these facilities will be provided service under either the Optional Rate or the General Service Rate.

Continued on Sheet No. D-8.00 Issued: Effective for Service


Continued From Sheet No. D-7.00 D5. RESIDENTIAL MULTIPLE FAMILY DWELLING RATE - (General and Heating) (Contd)

RATE

Customer Charge: (See Sheet No. D-10.00 for meter classifications.)

Daily Monthly Meter Class I $ 0.3945 per customer, plus $ 12.00 per customer, plus Meter Class II $ 1.0849 per customer, plus $ 33.00 per customer, plus Meter Class III $ 1.0849 per customer, plus $ 33.00 per customer, plus Meter Class IV $ 1.0849 per customer, plus $ 33.00 per customer, plus

Distribution Charge: (See Sheet No. D-10.00 for meter classifications.)

Meter Class I $ 1.7815 per Mcf, plusMeter Class II $ 1.7815 per Mcf, plusMeter Class III $ 1.7815 per Mcf, plusMeter Class IV $ 1.7815 per Mcf, plus

Gas Cost Recovery Charge

The monthly gas cost recovery charge as set forth on Sheet No. D-2.00.

Supplemental Charges This rate is subject to the Supplemental Charges set forth on Sheet Nos. D-1.00, D-1.01 and D-1.02.


A charge of $45.00, payable in either a flat amount or three equal installments, will be made to partially cover the cost of restoring service when it has been temporarily discontinued at the customer's request.

Late Payment Charge and Due Date

A late payment charge of 2%, not compounded, net of sales tax, will be added to any bill which is delinquent. Customers participating in the Winter Protection Plan will not be assessed the late payment charge. The due date shall be 21 days following the date of mailing.




GAS ALLOCATION PROCEDURE

This rate schedule is subject to the provisions of Rule C2.7.

SPECIAL TAXES

(1) In municipalities which levy special taxes, license fees, or street rentals against the Company, and which levy has been successfully maintained, the standard of rates shall be increased within the limits of such municipalities so as to offset such special charges and thereby prevent the customers in other localities from being compelled to share any portion of such local increase.

(2) Bills shall be increased to offset any new or increased specific tax or excise

imposed by any governmental authority upon the Company's production, transmission or sale of gas.

RULES AND REGULATIONS

Service under this rate schedule shall be subject to the Standard Rules and Regulations of the Company.

SPECIAL PROVISIONS The Consumer Standards and Billing Practices are not applicable to service under this rate schedule (Case No. U-4240).

Continued on Sheet No. D-10.00 Issued: Effective for Service By J F Schott On and After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission Dated:



METER CLASSIFICATIONS For application of the Monthly Customer Charge under this rate schedule, the Company's gas meters are designated in one of the following classifications:

Meter Class I Meter Class II Meter Class III Meter Class IV(Less than 400 CFH) (400-1000 CFH) (Over 1000 CFH) (Over 1,000 CFH) (without pressure (with pressure or or temperature temperature correcting devices) correcting devices)American AL-175-TC Sprague 1000-TC Rockwell 3000-TC Rockwell 3000-TCAmerican 225-TC American 425-TC Rockwell 5000-TC Rockwell 5000-TCAmerican AL-250-TC American 1000-TC Roots 1.5M TC Roots 1.5M-TCRockwell 175-TC Rockwell 415-TC Roots 3M Roots 3M Rockwell 250-TC Rockwell 750-TC Roots 3M TC Roots 3M TCRockwell 200-TC Rockwell 1000-TC Roots 5M Roots 5M Sprague 175-TC Rockwell 1600-TC Roots 5M TC Roots 5M TCRockwell 275-TC Roots 7M Roots 7M Roots 7M TC Roots 7M TC Roots 11M Roots 11M Roots 16M Roots 16M Roots 23M Roots 23M Roots 38M Roots 38M Rockwell T-18 Rockwell T-18 Rockwell T-30 Rockwell T-30 Rockwell T-60 Rockwell T-60 Rockwell T-140 Rockwell T-140

Continued on Sheet No. D-11.00 Issued: Effective for Service By J F Schott On and After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission


Continued from Sheet No. D-10.00

D6. SMALL GENERAL SERVICE RATE - (General and Heating)

AVAILABILITY

Subject to limitations and restrictions contained in orders of the Michigan Public Service Commission in effect from time to time and in the Rules and Regulations of the Company, service is available under this rate schedule to any non-residential customer for any purpose.

RATE



Distribution Charge $ 1.7815 per Mcf, plus

Gas Cost Recovery Charge

The monthly gas cost recovery charge as set forth on Sheet No. D-2.00.

Supplemental Charges This rate is subject to the Supplemental Charges set forth on Sheet Nos. D-1.00, D-1.01 and D-1.02.



Delayed Payment Charge and Due Date

A delayed payment charge of 2%, shall be applied to the unpaid balance outstanding not compounded, net of sales tax, of any bill which is not paid on or before the due date shown thereon. The due date shall be 21 days following the date of mailing.



Continued from Sheet No. D-12.00

D7. LARGE GENERAL SERVICE RATE - (General and Heating)

AVAILABILITY

Subject to limitations and restrictions contained in orders of the Michigan Public Service Commission in effect from time to time and in the Rules and Regulations of the Company, service is available under this rate schedule to any non-residential customer for any purpose.

RATE



Distribution Charge $ 1.0578 per Mcf, plus

Gas Cost Recovery Charge The monthly gas cost recovery charge as set forth on Sheet No. D-2.00.

Supplemental Charges:

This rate is subject to the Supplemental Charges set forth on Sheet Nos. D-1.00, D-1.01 and D-1.02.



Delayed Payment Charge and Due Date

A delayed payment charge of 2% shall be applied to the unpaid balance outstanding not compounded, net of sales tax, of any bill which is not paid on or before the due date shown thereon. The due date shall be 21 days following the date of mailing.


Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 17 of 24 MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. D-15.00 M.P.S.C. No. 2 – GAS Replaces First Revised Sheet No. D-15.00

Continued from Sheet No. D-14.00 D8. GAS LIGHTING RATE

AVAILABILITY

Subject to limitations and restrictions contained in orders of the Michigan Public Service Commission in effect from time to time and in the Rules and Regulations of the Company. Rate Schedule Distribution Charge Residential - $ 1.7815 per Mcf

Commercial - $ 1.7815 per Mcf

Street Lights - (In accordance with the terms of the service agreement) Gas Cost Recovery Charge The monthly gas cost recovery charge as set forth on Sheet No. D-2.00.

Supplemental Charges This rate is subject to the Supplemental Charges set forth on Sheet Nos. D-1.00,

D-1.01 and D-1.02 RULES AND REGULATIONS

Service under this rate schedule shall be subject to the Standard Rules and Regulations of the Company plus the following condition:

No additional gas burning devices may be attached to the service connection for light(s) served under this rate.

SPECIAL TAXES

(1) In municipalities which levy special taxes, license fees, or street rentals against

the Company, and which levy has been successfully maintained, the standard of rates shall be increased within the limits of such municipalities so as to offset such special charges and thereby prevent the customers in other localities from being compelled to share any portion of such local increase.

(2) Bills shall be increased to offset any new or increased special tax or excise

imposed by any governmental authority upon the Company's production, transmission or sale of gas.

Issued: Effective for Service By: J. F. Schott On and After: VP Regulatory Affairs Issued Under Authority of

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 18 of 24 MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. E-13.00 M.P.S.C. No. 2 – GAS Replaces First Revised Sheet No. E-13.00

Continued From Sheet No. E-12.00

E5. TRANSPORTATION SERVICE AND RATES (Contd) E5.3 AGGREGATION OF ACCOUNTS OPTION.

(b) Only the subsidiary accounts will be eligible for aggregation with the master account. To

qualify as a subsidiary account a facility must be served under any of the Sales Service Rates or Transportation Service Rates. The customer, or the customer’s agent, must specify which of the other facilities will be designated as a subsidiary account. The customer may designate some or all of its other facilities as subsidiary accounts.

(c) The facility designated as the master account shall be subject to and billed under the

provisions of its transportation tariff. Facilities designated as subsidiary accounts shall be subject to all the terms and conditions of the master account tariff, except that each subsidiary account will pay the customer charge, distribution charge and all applicable Supplemental charges as set forth on Sheet Nos. D-1.00, D-1.01 and D-1.02 in effect for its designated sales or transportation rate, rather than the customer charge and transportation charge in effect for the master account.

E5.4 RATES AND CHARGES Transportation Service Rate Monthly Charges: TR-1 TR-2 TR-3

Customer Charge -

Each Meter $ 850.00 / meter $ 2,250.00 / meter $ 3,050.00 / meter

Transportation Rates:

Peak (November to March) $ 0.7777 per Mcf $ 0.4796 per Mcf $ 0.4651 per Mcf Off-Peak (April to October) $ 0.6277 per Mcf $ 0.3296 per Mcf $ 0.3151 per Mcf

Optional Discount Rates - The Company, at its discretion, may negotiate lower rates for individual customers, down to a minimum of $0.20 per Mcf.

The Company, at its option, may require the installation of a heating value measurement device and the payment by the customer of a $250.00 monthly heating value measurement charge under the following conditions:

(a) If the customer refuses to include in its gas transportation service contract a provision that

holds the Company harmless for any damages resulting from measuring errors; or

(b) If the customer demands that heating value measurement equipment be installed. Continued on Sheet No. E-14.00 Issued: Effective for Service By: J. F. Schott On and After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 19 of 24 MICHIGAN GAS UTILITIES CORPORATION Fourth Revised Sheet No. E-14.00 M.P.S.C. No. 2 – GAS Replaces Third Revised Sheet No. E-14.00

Continued From Sheet No. E-13.00

E5. TRANSPORTATION SERVICE AND RATES (Contd)

E5.5 GAS COST RECOVERY

Gas transported under this rate is not subject to adjustments for fluctuations in the cost of purchased gas as stated in Rule C9 of the Company’s Rules, Regulations, and Rate Schedules, M.P.S.C. No. 2.

E5.6 SUPPLEMENTAL CHARGES

This rate may be subject to the Supplemental Charges set forth on Sheet No. D-1.00, D-1.01 and D-1.02.

E5.7 GAS-IN-KIND

The Company shall retain 0.31% of all gas received at the delivery point(s) to compensate it for the company-use and lost-and-unaccounted-for gas on the Company’s system. This volume shall not be included in the quantity available for redelivery to the customer.

E5.8 MONTHLY LOAD BALANCING

MONTHLY IMBALANCES: As imbalances occur, the Company and the customer will attempt to correct them within the same month in which they occur. Failing such corrections, the Company will cash-out the imbalances as described below:

ANNUAL CONTRACT QUANTITY (ACQ) is defined as the quantity of gas, as specified in the transportation contract between the customer and the Company, that is based on the customer’s maximum historical 12-month usage (determined from the customer’ 36-month base period) plus adjustments for known or expected changes.

AUTHORIZED TOLERANCE LEVEL (ATL) is defined as 5% of the customer’s ACQ. The Company is obligated to retain excess deliveries of gas on behalf of the customer up to its ATL, without additional charge.

EXCESS DELIVERIES are defined as gas delivered to the Company, on behalf of the customer, less gas in kind and gas redelivered to the customer, on a monthly basis.

ATL BALANCE is defined as the cumulative balance of excess deliveries from month to month, up to the customer’s ATL. The ATL balance may be carried forward from month to month without additional charge. The Company will inform the customer of its current ATL balance along with its monthly billing.

Continued on Sheet No. E-15.00

Issued: Effective for Service On and By: J. F. Schott After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 20 of 24 MICHIGAN GAS UTILITIES CORPORATION Third Revised Sheet No. E-17.00 M.P.S.C. No. 2 – GAS Replaces Second Revised Sheet No. E-17.00

Continued From Sheet No. E-16.00 E5. TRANSPORTATION SERVICE AND RATES (Contd)

Option B – “Pooling by Pipeline” (Contd)

Deliveries are pooled together by adding the positive and negative imbalances for each customer in the pool. A fee of $25.00 per month shall be imposed on each imbalance paper pool, with the fee billed to the marketer, broker, or aggregator that is designated as the pool’s representative.

E5.9 UNAUTHORIZED USAGE OR EXCESS DELIVERIES WHEN SERVICE IS INTERRUPTED,

CURTAILED, OR AN OFO IS IN EFFECT

Penalties for unauthorized usage or excess deliveries by a customer during a period of curtailment, OFO or interruption of gas service shall be assessed charges and cashed-out in accordance with the provisions of the Company’s Rule C3.2 - CURTAILMENT OF GAS SERVICE.

E5.10 AUTHORIZED TOLERANCE LEVEL RESTRICTIONS:

(a) Monthly withdrawals from storage during February through April will be limited to 3% of

the transportation customer’s ACQ. Withdrawals in excess of that limit may be authorized but are subject to the Company’s sole judgment and prior approval pursuant to appropriate terms and conditions. Without prior approval, if in any month the volume of gas received by the Company, less the allowance for gas-in-kind plus the 3% of the transportation customer’s ACQ is less than the volume of gas taken by the customer at the point of delivery, then all excess ATL delivery volumes above the 3% threshold will be cashed out in accordance with the Negative Imbalance provisions “% Monthly Nomination Over 5%”, at the high price for the MichCon City Gate Index.

(b) Injections into storage during September and October through November will be limited

to no more than 1.0% of ACQ without approval from the Company. Injections during the September and October through November period which exceed 1.0% shall permit the Company to refuse to receive any additional volume of gas for that customer until the Company has satisfied itself that the volume of gas retained for the customer is less than the ATL. All volumes delivered in excess of the 1.0% of ACQ level will be cashed-out in accordance with the Positive Imbalance provisions “% Monthly Nomination Over 5%”, at the low price for the MichCon City Gate Index.

(c) Daily nominations cannot exceed the percentage of expected daily usage that is

imposed upon the Company by the Interstate pipelines, without approval of the Company. Nominations that exceed the limitation shall be subjected to overrun charges and imbalance penalties, as imposed by the Interstate pipelines.

(d) For purposes of this provision (Subsections (a), (b) and (c) above), pooling will be

allowed on a supplier-by-supplier basis at the city gate. Issued Effective for Service By: J. F. Schott On and After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 21 of 24 MICHIGAN GAS UTILITIES CORPORATION Second Revised Sheet No. F-2.00 M.P.S.C. No. 2 – GAS Replaces First Revised Sheet No. F-2.00

Continued From Sheet No. F-1.00

F1. GENERAL PROVISIONS (Contd.)

(5) Supplier Pricing: A Supplier may have as many pricing pools as desired shall be limited to no more than a total of ten (10) Pricing Categories. A Supplier will not be permitted to add more than two (2) Pricing Categories per month, unless prior approval is obtained from the Company. Each month, all customers within a Pricing Categorypricing pool shall be billed the same price, as designated by the Supplier. A Supplier shall pay a monthly Administrative Fee of $100.00 per Supplier-designated Pricing Category. A “Pricing Category” shall be defined as a pricing pool that assesses the same rate for each of the Company’s five operating districts. The Company reserves the right to require additional pools to meet operational requirements.

(6) Daily Delivery Obligations: The Company will provide each Supplier with a monthly

schedule of quantities for delivery of gas into the Company system on behalf of the Supplier's customers for each Pricing Category and delivery pools behind each of the Company’s five operating districts. Prior to the closing bid day of futures trading for the month, Seven (7) business days prior to the end of the preceding month, the Company will issue a Daily Delivery Obligation (DDO). The DDO will establish the anticipated daily quantity of gas to be delivered to the Company at the Point(s) of Receipt designated by the Company. The DDO will generally be based upon the pooled customers’ historical use for the prior year, adjusted for the prior year’s weather. This schedule may be updated by the Company on a monthly basis. The Company reserves the right to take into consideration the Supplier’s cumulative imbalance in determining each month’s DDO. The DDO is subject to intra-month changes as operational conditions dictate. If the Company requires an increase or decrease in flow requirements within any month, the Company shall issue a DDO Change Notice to the Supplier as soon as possible but no later than twenty-four (24) hours prior to the start of the Gas Day. The Company shall issue such notices in a non-discriminatory manner. Scheduled daily volumes for GCC customers for electric peakers, greenhouses, grain dryers, asphalt plants and large loads without consistent or historical load information may be determined by the Company on a different basis than set forth above.

A Supplier that fails to deliver the required DDO quantity on any day, shall pay a per MMBtu “Failure Fee” for the difference between the required DDO and the actual amount delivered in the amount of $6.00 per MMBtu ($10.00 per MMBtu during periods of Company-declared supply emergency in accordance with Rule C3.2, Curtailment of Gas Service) plus the higher of (a) the cost of gas billed to sales customers pursuant to the Company's Rule C9 or (b) the current highest spot price paid for gas delivered to ANR Pipeline Company, Panhandle Eastern Pipe Line Company, Trunkline Gas Company, the MichCon index or at Chicago city gate for the corresponding date as published in Gas Daily, plus associated firm pipeline delivery costs. In addition, the Company may assess up-stream penalties to the Supplier to the extent that the Company has identified the Supplier as the cause of the penalty. (Failure Fees collected by the Company shall be reflected as a reduction to the GCR Cost of Gas Sold and identified separately on annual reconciliation reports under Rule C9.)

A Supplier who fails to deliver gas on successive days such that its Failure Fee liability exceeds its cash deposit, letter of credit or surety bond, shall be subject to having its Authorized Supplier status revoked. Subject to Rule C2, Controlled Service, the Supplier’s customers shall become sales rate customers of the Company.

Continued on Sheet No. F-3.00

Case No. U-17273 Witness: D. J. Tyler Exhibit A-6 (DJT-1) Schedule F5 Page 22 of 24 MICHIGAN GAS UTILITIES CORPORATION Third Revised Sheet No. F-3.00 M.P.S.C. No. 2 – GAS Replaces Second Revised Sheet No. F-3.00

Continued From Sheet No. F-2.00 F1. GENERAL PROVISIONS (Contd.)

(7) Proof Of Capacity: The Supplier shall be responsible for obtaining sufficient pipeline capacity to meet its delivery obligations.

(8) Gas delivered into the Company’s system shall comply with Rule B1, Technical Standards

for Gas Service, Part 8 Gas Quality.

(9) Nominations: Each Supplier shall notify the Company's Gas Transportation Services Department of the daily quantity of gas (in MMBtu) that the Supplier is nominating for delivery on behalf of each Supplier-designated monthly Pricing Category and each associated geographic delivery pool. Such nominations shall be submitted by 11:30 AM Central time prior to the effective day of the proposed delivery.

(10) Gas-In-Kind: The Company shall retain 0.31% of all gas received at the delivery point(s)

to compensate it for company-use and lost-and-unaccounted-for gas on the Company’s system. This volume shall not be included in the quantity available for redelivery to the customer.

(11) Customer Billing: All customer billing and remittance processing functions for services

provided under Rate CC will be performed by the Company. The Supplier will be charged a monthly fee of $0.46 per customer account. The Company will be responsible for credit and collection activities for the amounts billed directly to the customer by the Company. The Supplier must, at least three business days prior to the start of each billing month, furnish to the Company, in a format acceptable to the Company, the price per Mcf or Ccf to be billed to each Supplier-designated Pricing Category on its behalf or the most recently supplied price will be used.

When a Supplier has more than one pool and delivers a monthly cumulative amount of gas to the Company that differs from the total DDO’s issued by the Company to the Supplier, the Company shall allocate any gas shortages to the highest priced pools first, when making remittances. For any monthly cumulative amounts of gas delivered to the Company in excess of the total DDO’s issued by the Company to the Supplier, the Company shall allocate such gas excess to the lowest priced pools first, when making remittances.

(12) Buy/Sell: The Company shall remit to the Supplier, approximately 21 business days from

the end of each calendar month, an amount for the cost of gas equal to the MMBtu quantities that the Supplier has delivered onto the Company's system, multiplied by the price per Mcf converted to MMBtu, billed to the Supplier's customers that month. The amount to be remitted shall be reduced for any applicable Administrative Fees, Billing Fees, and Failure Fees, amounts owed under the annual price reconciliation per Paragraph (13) below and/or other amounts owed to the Company pursuant to the Company’s tariff.

(13) Annual Reconciliation: Within 60 working days after the end of the June billing cycle, or

upon revocation of a Supplier’s Authorized Supplier status, the Company will determine if a reconciling adjustment is necessary, both price and volume will be reviewed.

The Company will compare:

(i) the weighted average price per MCF billed the customer on behalf of the Supplier with the Company’s actual weighted average cost of gas (WACOG), and




(ii) the volumes delivered by the Supplier less Gas In Kind, converted to Mcf, with the billed customer consumption over the program year.

A reconciling adjustment will only be made when:

(i) the difference between the weighted average price per Mcf billed the customer on behalf of the Supplier and the Company’s actual WACOG exceeds ten percent (10%) of the Company’s actual WACOG, and

(ii) the difference between the volumes delivered by the Supplier less Gas-In-Kind,

converted to Mcf, and billed customer consumption exceeds ten percent (10%) of billed customer consumption.

The reconciling adjustment, if made, will be reflected on the next monthly remittance to the Supplier. (Amounts collected or remitted by the Company under the Annual Reconciliation mechanism shall be reflected as a component of the GCR Cost of Gas Sold and identified separately on annual reconciliation reports under Rule C9.) The following table enumerates the various pricing and supply conditions that will be considered in the annual reconciliation process:

Annual Reconciliation Pricing/Supply Conditions

1. Supplier’s weighted average price 2. Supplier’s weighted average price billed is higher than the Company’s billed is less than the Company’s actual WACOG and delivered volumes, actual WACOG and delivered volumes, less Gas-In-Kind, exceed billed customer less Gas-In-Kind, exceed billed customer consumption. consumption.

3. Supplier’s weighted average price 4. Supplier’s weighted average price

billed is higher than the Company’s billed is less than the Company’s actual WACOG and billed customer actual WACOG and billed customer consumption exceeds delivered volumes. consumption exceeds delivered volumes.

Scenario #1: Remittance to Supplier will be reduced for volumes delivered in excess of billed customer consumption, less Gas-In-Kind, at the difference between the Company’s actual WACOG and the Supplier’s weighted average price.

Scenario #2: Remittance to Supplier will be increased for amounts delivered in excess of customer billed consumption, less Gas-In-Kind, at the difference between the Company’s actual WACOG and the Supplier’s weighted average price.

Scenario #3: Remittance to Supplier will be increased for amounts billed to customers in excess of the volumes delivered at the difference between the Company’s actual WACOG and the Supplier’s weighted average price.

Scenario #4: Remittance to Supplier will be reduced for amounts billed to customers in excess of the volumes delivered at the difference between the Company’s actual WACOG and the Supplier’s weighted average price.




(14) If the Commission or its Staff determines that a Supplier has not complied with the terms and conditions of the Program, The Commission or its Staff shall direct a utility or utilities to suspend the Supplier’s Authorized status until the Commission or its Staff determines that necessary changes have been made to comply with the requirements. Failure to make the necessary changes, or further non-compliance with the requirements of the terms and conditions of the Program may result in the Supplier’s termination from the Program. If a Supplier is terminated, subject to Rule C2, Controlled Service, its customers shall become sales rate customers of the Company.

(15) For purposes of reconciling amounts owed between the Company and a Supplier, the

Company will convert customer consumption from Mcf to MMBtu using daily system-average Btu content by billing cycle.

(16) Where used in this rule, the term "month," unless otherwise indicated, means billing month

when referring to customer consumption and calendar month when referring to deliveries by Suppliers.

(17) The Company may disclose, at such times as requested by the Commission or its staff, the

gas rates charged to Rate CC customers.

(18) The Company shall have the authority to issue operational flow orders (OFO’s), or take other action which it deems necessary, to ensure system reliability, even if such action may be inconsistent with other provisions of these Program Rules.

(19) The Company will act as Supplier of last resort under the Program.

(20) A Supplier must include the Company’s required tariff language in all of its contracts.

(21) If a customer has a complaint against a Supplier, the customer should try to resolve it first

with the Supplier. If the complaint is unresolved, the customer should involve the Commission by contacting the Commission Staff. Should the customer choose to involve the Company in a complaint, the Company shall forward the complaint information to the Commission Staff and the Supplier for resolution. The Company shall have no responsibility for resolving disputes between customers and Suppliers but shall provide information if requested by the customer or Commission Staff.

(22) The Transportation Standards of Conduct, Rules E4.2 and E4.3, shall apply to the GCC

program (23) The annual load requirement, DDO’s, delivery schedules, delivery shortfalls, Failure Fees

and annual reconciliations shall apply separately to each Supplier designated Pricing Category.


Issued: Effective for Service By: J. F. Schott On and After: VP Regulatory Affairs Issued Under Authority of Green Bay, Wisconsin Michigan Public Service Commission

Case No.: U-17273Witness: D.J. TylerExhibit A-6 (DJT-1)

Schedule F6Page 1 of 1

MARGIN MARGIN PROPOSED CLASS MARGIN REVENUE REVENUE MARGIN SALES SURCHARGE

RATE CLASS REVENUE ($) INCREASE (%) INCREASE ($) REVENUE ($) (MCF)(1) (2) (3) (4) (5) (6)

Residential $41,529,322 12.9328% $5,370,900 $46,900,223 13,391,087.3 $0.4011 per MCFMulti-Family 485,090 12.9328% 62,736 547,826 269,316.3 $0.2329 per MCFSmall Commercial & Industrial 12,991,676 12.9328% 1,680,186 14,671,862 6,565,742.4 $0.2559 per MCFLarge Commercial & Industrial 430,824 12.9328% 55,718 486,542 333,687.6 $0.1670 per MCFTR-1 Transport 2,408,782 12.9328% 311,523 2,720,305 1,821,164.8 $0.1711 per MCFTR-2 Transport 2,614,176 12.9328% 338,086 2,952,262 3,883,380.9 $0.0871 per MCFTR-3 Transport 1,683,099 12.9328% 217,672 1,900,771 3,740,606.9 $0.0582 per MCF

Total $62,142,969 $8,036,820 $70,179,789 30,004,986.2

$8,036,820

2) 2012 Margin Revenues

3) Proposed Interim Margin Revenue Increase (%)

4) Proposed Interim Margin Revenue Increase ($) (2) x (3)

5) Proposed Interim Margin Revenues (2) + (4)

6) 2014 Forecasted sales

7) Proposed Surcharge (4) / (6)

1) Rate Schedule Grouping (Residential = Residential General, Heating, Lighting, Choice and Aggregated Transport; Multi-Family = Multi-Family Meter Classes I - IV, Choice and Aggregated Transport; Small C&I = Small C&I General, Heating, Lighting, Choice and Aggregated Transport; Large C&I = Large C&I General, Heating, Choice and Aggregated Transport) The rates for Special Contract customers as determined by contract. Therefore, no interim increase is proposed for Special Contract Customers.

(7)

Michigan Gas Utilities CorporationAllocation of Interim Rate Increase

Equal Percentage Increase of Margin Revenues

($/MCF)

STATE OF MICHIGAN



DIRECT TESTIMONY OF

JOHN R. WILDE

FOR


June 7, 2013

1

STATE OF MICHIGAN


* * * * *


QUALIFICATIONS OF

JOHN R. WILDE PART I


A. My name is John R. Wilde. My business address is Integrys Energy Group, Inc. 2

(“Integrys”), 700 North Adams Street, P.O. Box 19001, Green Bay, WI 54307-9001. I 3

am a Vice President for Integrys, and am responsible for the tax function for Integrys 4

and its subsidiaries including Michigan Gas Utilities Corporation (“MGUC”). I am 5

testifying on behalf of MGUC in support of its application in this proceeding for 6

authority to increase its natural gas rates. 7

8

Q. Please describe your educational, professional, and utility background. 9

A. I graduated from Saint Norbert College, De Pere, Wisconsin in 1984 with a Bachelor 10

of Business Administration degree in Accounting. I have a graduate certificate in 11

state and local taxation, as well as a Masters Degree in Taxation, from the University 12

of Wisconsin-Milwaukee. I have been employed by Integrys or its predecessors 13

since 1984, and since 1986 I have been employed in the Corporate Tax Department. 14

15

Q. Have you previously testified in any regulatory proceedings? 16

A. Yes, I have. I have testified regarding depreciation, tax compliance, tax accounting, 17

2

and regulatory tax matters before a number of regulatory bodies, including the 1

Federal Energy Regulatory Commission, and utility commissions in Illinois, Michigan, 2

Minnesota, and Wisconsin. 3

3

JOHN R. WILDE DIRECT TESTIMONY

PART II Q. What is the purpose of your pre-filed direct testimony in this docket? 1

A. I present and support MGUC’s treatment in the instant rate case of a federal tax Net 2

Operating Loss (“NOL”) carryover from 2013 and 2014 by applying long standing 3

regulatory practices related to accounting for income taxes. 4

5

Accounting for a Federal Tax Net Operating Loss (“NOL”) Carryover 6 Q. For the 2014 test year, has MGUC included a deferred tax asset related to a 7

Federal NOL? 8

A. Yes, MGUC has included a deferred tax asset (“DTA”) for a NOL carry forward. The 9

DTA represents MGUC’s stand-alone operating income NOL that arises in 2012 and 10

2013 due primarily to bonus depreciation. 11

12

Q. Has MGUC recently experienced NOLs? 13

A. Yes, MGUC has experienced Net Operating Losses in recent years, due to bonus 14

tax depreciation deductions, and adjustments related to changes in methods of 15

accounting. However, until this rate case, MGUC was not in the position of having to 16

reflect a carry forward of a NOL balance from a prior year. 17

18

Q. What caused MGUC’s NOL? 19

A. MGUC’s 2012 and 2013 NOLs being carried forward are primarily the result of the 20

enactment of extensions allowing continued bonus depreciation deductions. 21

22

Q. What is bonus depreciation and what is its purpose? 23

A. Bonus depreciation is an acceleration of tax depreciation deductions to the first year 24

4

qualified property goes in service. The acceleration is based on a set percentage of 1

the tax basis of the qualified property. Congress enacted the bonus depreciation 2

provision in an effort to stimulate investment and create jobs at various times and at 3

various levels over the past decade. Bonus depreciation provides MGUC a source of 4

zero cost capital and has kept rates lower than they otherwise would have been. 5

However, due to the number of back-to-back years MGUC and the Integrys 6

consolidated group have been entitled to bonus depreciation deductions, as of the 7

end of 2013 MGUC is in the position of carrying the tax benefit of those deductions 8

forward in the form of a NOL carry forward balance. 9

10

Q. For tax purposes, what happens when a utility has more deductions, including 11

accelerated depreciation and bonus depreciation, than it has income? 12

A. If a utility has more tax deductions than taxable income in a given tax year, it has a 13

tax NOL. 14

15

Q. How can a NOL be used? 16

A. For tax purposes, NOLs can be carried back and applied against taxable income (if 17

any) in the two prior years. Then any remaining unused NOL is carried forward until 18

utilized for up to 20 years. The determination if a standalone entity can carry a loss 19

back or forward to be benefited is subject to the consolidated group of company’s 20

taxable income position in the applicable carryback and carryforward period. 21

22

Q. What is the status of Integrys’ consolidated NOL position for 2012 and 2013? 23

A. The Integrys consolidated group will generate an NOL in both 2012 and 2013, for the 24

same primary reason MGUC is generating an NOL during those years. As a result of 25

taking advantage bonus depreciation for several years, the Integrys consolidated 26

5

group will also be in a NOL carry-forward position for 2012 and 2013. 1

2

Q. What is the status of Integrys’ consolidated NOL position for 2014? 3

A. For 2014, Integrys consolidated is assumed to be in an income position sufficient to 4

absorb the NOL carry forward from 2012 and 2013. Therefore in 2014, MGUC’s 5

NOL DTA reverses over the course of the year. 6

7

Q. If a DTA is included as zero cost capital, what is the result? 8

A. MGUC would be in violation of the tax normalization rules. 9

10

Q. Please explain the specific tax normalization rule that relates to a NOL. 11

A. The normalization rules related to a federal NOL can be summarized as a 12

requirement that the utility has to have realized the tax cash flow benefit of claiming 13

accelerated depreciation before the deferred tax liability that results from claiming 14

accelerated depreciation is included in rate base. Therefore, the tax normalization 15

rules require MGUC to carry a deferred tax asset for the NOL balance from 2012 and 16

2013 that resulted from claiming accelerated tax depreciation, until used during 17

2014. An example of MGUC NOL situation and the IRS findings in that case can be 18

found in Private Letter Ruling (“PLR”) 8818040. In that ruling, the taxpayer did not 19

realize the entire tax benefit from the ACRS [Accelerated Cost Recovery System] 20

depreciation claimed in 1985 and 1986 because the depreciation resulted in a NOL 21

carryover to 1987. Therefore, in order to reflect the tax benefit of the NOL carryover 22

to 1987, the taxpayer reduced its deferred federal income tax expense and liability 23

for 1985 and 1986 for financial reporting purposes. 24

25

26

6

Q. Will including the DTA in cost of capital in this proceeding be akin to what 1

occurred in this circumstance as described in the PLR? 2

A. Yes, it would. Recording the effects of a NOL as a DTA is the modern day 3

equivalent of the reduction in deferred tax liability in the ruling. By including the 4

DTA related to the NOL, the tax benefit recorded in the deferred tax liability related to 5

accelerated depreciation is effectively eliminated until such time as the loss is 6

realized. 7

8

Q. What effect would a normalization violation have on customers? 9

A. A violation of the normalization rules would create severe detriment for both 10

customers and MGUC. The normalization rules are long-standing and Congress has 11

been unwavering in its mandate. These rules have been in force and the impact of 12

noncompliance has been known to utilities and their regulators for the past four 13

decades. Compliance with these rules is not optional and cannot be violated directly 14

or indirectly. Thus, it is important not to take steps that would have the unintended 15

consequence of losing the ability to continue to claim the rate base reducing impacts 16

of accelerated and bonus depreciation. 17

18

Q. Although Integrys consolidated is currently forecasting an NOL position in 19

2014, what would MGUC and the Commission be required to do if the final rate 20

relief in the instant rate case resulted in a NOL for MGUC and Integrys 21

consolidated? 22

A. If both MGUC’s operating income and Integrys’ consolidated forecasted tax positions 23

project a federal NOL, an increase to the NOL DTA must be computed and included 24

in the final MGUC capital structure earning a return. 25

26

7


A. Yes, it does. 2