DEFM14C 1 d349449ddefm14c.htm DEFM14C DEFM14C
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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

SCHEDULE 14C

SCHEDULE 14C INFORMATION

Information Statement Pursuant to Section 14(c)

of the Securities Exchange Act of 1934

 

 

 

Filed by the Registrant  ☒    Filed by a Party other than the Registrant  ☐

 

Check the appropriate box:
  Preliminary Information Statement
  Confidential, for Use of the Commission Only (as permitted by Rule 14c-5(d)(2))
  Definitive Information Statement

Midcoast Energy Partners, L.P.

(Name of Registrant as Specified In Its Charter)

 

Payment of Filing Fee (Check the appropriate box):
  No fee required.
  Fee computed on table below per Exchange Act Rules 14c-5(g) and 0-11.
  (1)  

Title of each class of securities to which transaction applies:

 

   

 

  (2)  

Aggregate number of securities to which transaction applies:

 

   

 

  (3)  

Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined):

 

   

 

  (4)  

Proposed maximum aggregate value of transaction:

 

   

 

  (5)   Total fee paid:
   
   

 

  Fee paid previously with preliminary materials.
  Check box if any part of the fee is offset as provided by Exchange Act Rule 0- 11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.
  (1)  

Amount Previously Paid:

 

   

 

  (2)  

Form, Schedule or Registration Statement No.:

 

   

 

  (3)  

Filing Party:

 

   

 

  (4)  

Date Filed:

 

   

 

 

 

 

 


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LOGO

1100 LOUISIANA STREET, SUITE 3300

HOUSTON, TEXAS 77002

NOTICE OF ACTION BY WRITTEN CONSENT

AND INFORMATION STATEMENT

WE ARE NOT ASKING YOU FOR A PROXY AND

YOU ARE REQUESTED NOT TO SEND US A PROXY

To the Common Unitholders of Midcoast Energy Partners, L.P.:

This notice of action by written consent and the accompanying information statement are being furnished to the holders of Class A common units representing limited partner interests (“Class A Common Units”) in Midcoast Energy Partners, L.P., a Delaware limited partnership (“MEP”), in connection with the Agreement and Plan of Merger, dated as of January 26, 2017 (the “Merger Agreement”), entered into by and among Enbridge Energy Company, Inc., a Delaware corporation (“EECI”), Enbridge Holdings (Leather) L.L.C., a Delaware limited liability company and wholly-owned subsidiary of EECI (“Merger Sub”), MEP and Midcoast Holdings, L.L.C., a Delaware limited liability company and the general partner of MEP (“MEP GP”), pursuant to which, among other things, and subject to the satisfaction or waiver of the conditions set forth therein, Merger Sub will be merged with and into MEP, with MEP surviving the merger (the “Merger”).

If the Merger is completed, you will be entitled to receive $8.00 in cash, without interest, less any applicable withholding taxes, for each Class A Common Unit you own.

The conflicts committee (the “MEP Committee”) of the board of directors of MEP GP (the “MEP GP Board”), consisting of three independent directors, has (1) unanimously determined that the Merger, the Merger Agreement and the Support Agreement (defined below) and the transactions contemplated by the Merger Agreement and the Support Agreement, including the Merger and the issuance of new Class A Common Units (the “Merger Transactions”), are fair and reasonable to and in the best interests of MEP, MEP’s subsidiaries and the holders of the outstanding Class A Common Units (other than EECI, Enbridge Energy Partners, L.P., a Delaware limited partnership (“EEP”), MEP GP and their respective affiliates) (the “MEP Unaffiliated Unitholders”), (2) approved the Merger Agreement, the Support Agreement and the Merger Transactions, (3) recommended that the MEP GP Board approve the Merger Agreement, the Support Agreement and the consummation of the Merger Transactions and (4) recommended that the MEP GP Board submit the Merger Agreement to a vote of MEP’s limited partners and recommend the approval of the Merger Agreement by MEP’s limited partners, such approval and recommendation by the MEP Committee constituting “Special Approval” as such term is defined in the First Amended and Restated Agreement of Limited Partnership of MEP, dated as of November 13, 2013, as amended, modified or supplemented from time to time (the “MEP Partnership Agreement”).

The MEP GP Board (acting based in part upon the recommendation of the MEP Committee and after receiving the approval of MEP GP’s sole member), has unanimously (1) determined that each of the Merger, the Merger Agreement, the Support Agreement and the Merger Transactions is fair and reasonable to and in the best interests of MEP, MEP’s subsidiaries and MEP’s limited partners, (2) approved the Merger Agreement, the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement and the consummation of the Merger Transactions, (3) resolved to submit the Merger Agreement to a vote of MEP’s limited partners by written consent, and (4) recommended approval of the Merger Agreement, including the Merger, by MEP’s limited partners.


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Under the applicable provisions of the MEP Partnership Agreement, the approval of the Merger Agreement requires the approval of at least a majority of the outstanding common units. As of February 15, 2017, EEP owns approximately 52% of MEP’s outstanding common units. As a result, EEP owns a sufficient number of common units to approve the Merger Agreement and the Merger Transactions on behalf of the holders of MEP common units. Concurrently with the execution of the Merger Agreement, MEP has entered into a support agreement (the “Support Agreement”) with EECI and EEP whereby EEP has agreed, in its capacity as a unitholder of MEP, to vote its units in favor of the Merger Agreement and the Merger Transactions.

Immediately prior to the closing of the Merger Transactions, EEP will deliver to MEP a written consent approving the Merger Agreement and the Merger Transactions. As a result, MEP has not solicited and is not soliciting your approval of the Merger Agreement or the Merger Transactions. Further, MEP does not intend to call a meeting of unitholders for purposes of voting on the approval of the Merger Agreement or the Merger Transactions.

The accompanying information statement provides you with detailed information about the Merger Agreement and the Merger Transactions. A copy of the Merger Agreement is attached as Annex A to the information statement and a copy of the Support Agreement is attached as Annex B to the information statement. We encourage you to read the entire information statement and its annexes, including the Merger Agreement and the Support Agreement, carefully. Please read “Material U.S. Federal Income Tax Considerations” for a more complete discussion of the U.S. federal income tax consequences of the Merger. All information in this information statement concerning MEP has been furnished by MEP. You may also obtain additional information about MEP from documents MEP has filed with the Securities and Exchange Commission.

No action by you is requested or required at this time. If the Merger is consummated, you will receive instructions regarding the surrender of your common units and payment for your common units.

Sincerely,

/s/ Dan A. Westbrook

Dan A. Westbrook

Chair of the Board of Directors of Midcoast

Holdings, L.L.C., the general partner of

Midcoast Energy Partners, L.P.

This information statement is dated April 7, 2017, and is first being mailed to holders of Class A Common Units on or about April 7, 2017.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES REGULATORY AGENCY HAS APPROVED OR DISAPPROVED THE MERGER, PASSED UPON THE MERITS OR FAIRNESS OF THE MERGER OR PASSED UPON THE ADEQUACY OR ACCURACY OF THE DISCLOSURE IN THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.


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TABLE OF CONTENTS

 

SUMMARY TERM SHEET

    1  

Parties to the Merger Transactions

    1  

The Merger

    2  

The Merger Consideration

    2  

Effects of the Merger

    3  

Information about the Action by Written Consent

    3  

Recommendation of MEP GP Board and MEP Committee

    4  

Opinion of Evercore Group L.L.C. – Financial Advisor to the MEP Committee

    4  

Support Agreement

    5  

EEM Conflicts Committee and the EEM Board

    5  

Interests of Certain Persons in the Merger

    6  

Regulatory Approvals Required for the Merger

    6  

Conditions to Completion of the Merger

    6  

Termination of the Merger Agreement

    7  

Effect of Termination; Remedies

    8  

Expenses Relating to the Merger

    8  

Financing of the Merger

    8  

Material U.S. Federal Income Tax Considerations

    8  

No Appraisal Rights

    9  

Accounting Treatment

    9  

Delisting and Deregistration of Class A Common Units

    9  

QUESTIONS AND ANSWERS ABOUT THE MERGER

    10  

SPECIAL FACTORS

    15  

Background of the Merger

    15  

Recommendation of the MEP Committee and the MEP GP Board; Reasons for Recommending Approval of the Merger Agreement and the Merger Transactions

    29  

Unaudited Financial Projections of MEP and MOLP

    35  

Opinion of Evercore Group L.L.C. – Financial Advisor to the MEP Committee

    38  

EEM Conflicts Committee and the EEM Board

    51  

Position of the Enbridge Parties, the MEP GP Board and the MEP Committee as to the Fairness of the Merger

    52  

Enbridge Parties’ Purpose and Reasons for the Merger

    52  

Effects of the Merger

    53  

Primary Benefits and Detriments of the Merger

    55  

Interests of Certain Persons in the Merger

    56  

Material U.S. Federal Income Tax Considerations

    57  

Financing of the Merger

    57  

Estimated Fees and Expenses

    57  

Regulatory Approvals Required for the Merger

    58  

Certain Legal Matters

    58  

Provisions for Unaffiliated Security Holders

    58  

No Appraisal Rights

    58  

Accounting Treatment of the Merger

    59  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

    60  

OTHER MATTERS

    62  

Householding of Materials

    62  

THE MERGER AGREEMENT

    63  

The Merger

    63  

Effective Time; Closing

    63  

Conditions to Completion of the Merger

    64  

 

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MEP GP Recommendation and MEP GP Adverse Recommendation Change

    64  

MEP Unitholder Approval

    65  

The Merger Consideration

    66  

Treatment of Long-Term Incentive Plan

    66  

Distributions

    66  

Surrender of Class A Common Units

    67  

Adjustments to Prevent Dilution

    67  

Withholding

    67  

Filings

    67  

Termination

    68  

Effect of Termination; Remedies

    69  

Conduct of Business Pending the Merger

    69  

Indemnification; Directors’ and Officers’ Insurance

    70  

MEP Committee

    71  

Amendment and Supplement

    71  

Waiver and Consent

    71  

Remedies; Specific Performance

    71  

Representations and Warranties

    71  

Additional Agreements

    72  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

    73  

Tax Considerations of the Merger to Holders of Class A Common Units

    73  

INFORMATION CONCERNING MEP

    75  

About MEP

    75  

Business and Background of Natural Persons Related to MEP

    75  

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

    87  

COMMON UNIT MARKET PRICE AND DISTRIBUTION INFORMATION

    90  

Common Unit Market Price Information

    90  

Distribution Information

    90  

INFORMATION CONCERNING THE ENBRIDGE PARTIES AND MERGER SUB

    92  

UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, DIRECTORS AND EXECUTIVE OFFICERS OF MEP AND THE ENBRIDGE PARTIES

    93  

Unit Ownership by MEP GP’s Directors and Executive Officers

    93  

Unit Ownership by EEP’s, EEM’s and EECI’s Directors and Executive Officers

    94  

Unit Ownership by Enbridge’s Directors and Executive Officers

    94  

Unit Ownership of Other 5% or More Unitholders

    94  

CERTAIN PURCHASES AND SALES OF CLASS A COMMON UNITS

    95  

DELISTING AND DEREGISTRATION OF CLASS A COMMON UNITS

    95  

WHERE YOU CAN FIND MORE INFORMATION

    96  

Annex A : Agreement and Plan of Merger

    A-1  

Annex B : Support Agreement

    B-1  

Annex C : Opinion of Financial Advisor

    C-1  

Annex D : Annual Report for the Year Ended December 31, 2016

    D-1  

 

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SUMMARY TERM SHEET

The following summary highlights selected information in this information statement and may not contain all of the information that may be important to you. Accordingly, MEP encourages you to read carefully this entire information statement, including all of the annexes attached to this information statement.

Parties to the Merger Transactions

Midcoast Energy Partners, L.P.

Midcoast Energy Partners, L.P. (“MEP”) is a publicly traded Delaware limited partnership formed by Enbridge Energy Partners, L.P. (“EEP”) to serve as EEP’s primary vehicle for owning and growing EEP’s natural gas and natural gas liquids (“NGL”) midstream assets in the United States.

The Class A common units representing limited partner interests in MEP (“Class A Common Units”) are listed on the New York Stock Exchange (the “NYSE”) under the symbol “MEP.”

The principal executive offices of MEP are located at 1100 Louisiana St., Suite 3300, Houston, Texas 77002, and its telephone number at that address is (713) 821-2000.

Midcoast Holdings, L.L.C.

Midcoast Holdings L.L.C., a Delaware limited liability company (“MEP GP”), is the general partner of MEP and is solely responsible for conducting the business and managing the operations of MEP.

The principal executive offices of MEP GP are located at 1100 Louisiana St., Suite 3300, Houston, Texas 77002, and its telephone number at that address is (713) 821-2000.

Enbridge Energy Partners, L.P.

EEP is a publicly traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets, as well as natural gas gathering, treating, processing, transportation and marketing assets in the United States. EEP is the sole member of MEP GP. EEP is not party to the Merger Agreement (defined below) but has executed the Support Agreement (defined below) in connection with the Merger Agreement.

The principal executive offices of EEP are located at 1100 Louisiana St., Suite 3300, Houston, Texas 77002, and its telephone number at that address is (713) 821-2000.

Enbridge Energy Company, Inc.

Enbridge Energy Company, Inc., a Delaware corporation (“EECI”), is the general partner of EEP. EECI, under a delegation of control agreement with Enbridge Energy Management, L.L.C., a Delaware limited liability company (“EEM”), delegated substantially all of its power and authority to manage the business and affairs of EEP to EEM. EECI owns the voting shares of EEM and elects all of the directors of EEM.

The principal executive offices of EECI are located at 1100 Louisiana St., Suite 3300, Houston, Texas 77002, and its telephone number at that address is (713) 821-2000.

Enbridge Holdings (Leather) L.L.C.

Enbridge Holdings (Leather) L.L.C. (“Merger Sub”) is a Delaware limited liability company and wholly-owned subsidiary of EECI, which was formed by EECI on January 17, 2017, solely for the purposes of effecting

 



 

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the Merger (as defined below). Merger Sub has not conducted any business operations other than those incidental to its formation and in connection with the transactions contemplated by the Merger Agreement (as defined below). Upon completion of the Merger, Merger Sub will cease to exist as a separate entity.

The principal executive offices of Merger Sub are located at 1100 Louisiana St., Suite 3300, Houston, Texas 77002, and its telephone number at that address is (713) 821-2000.

Relationship of the Parties to the Merger Transactions

Enbridge Inc. (“Enbridge”), a Canadian corporation, is the ultimate parent of EECI, EEM, EEP and MEP. EECI is an indirect wholly owned subsidiary of Enbridge. Through its ownership of EECI, Enbridge has a controlling interest in both EEP and MEP. EECI is the sole general partner of EEP and has delegated substantially all of its general partner authority to manage the business and affairs of EEP to EEM. EECI also owns all of the voting shares of EEM and has the right to appoint and remove all of the members of the board of directors and officers of EEM. As of December 31, 2016, Enbridge and its consolidated subsidiaries owned an effective 41.7% interest in EEP, through ownership of EEM and EECI. EEP is the sole member of MEP GP, which is the sole general partner of MEP. Through its ownership of Class A Common Units, subordinated units representing limited partner interests in MEP (the “Subordinated Units”) and its ownership of MEP GP, EEP owned, as of December 31, 2016, an effective 53.9% interest in MEP. Neither MEP nor its subsidiaries have any employees. None of MEP GP’s executive officers are directly employed by MEP and are, instead, employed by Enbridge and its affiliates.

For more information regarding these relationships and the related party transactions between MEP, EEP and EECI, see “Special Factors—Interests of Certain Persons in the Merger.”

The Merger

Pursuant to the Agreement and Plan of Merger, dated as of January 26, 2017, entered into by and among EECI, Merger Sub, MEP and MEP GP, as it may be amended from time to time (the “Merger Agreement”), according to which the parties have agreed to consummate the transactions contemplated by the Merger Agreement and the Support Agreement, including the Merger (as defined below) and the issuance of the New Class A Common Units (as defined below) (the “Merger Transactions”), Merger Sub will merge with and into MEP, with MEP surviving the Merger and continuing to exist as a Delaware limited partnership (the “Merger”). Following the consummation of the Merger, EECI will own approximately 48% of the limited partner interests in MEP, and EEP will own the remaining approximate 52% of the limited partner interests and 2% general partner interest in MEP. The Merger will become effective upon the filing of a properly executed certificate of merger with the Secretary of State of the State of Delaware or at such later date and time as may be agreed by EECI and MEP and set forth in the certificate of merger (the “Effective Time”). Through the Merger, EECI will acquire all of the outstanding Class A Common Units, other than those held by EECI, EEP, MEP GP and their respective affiliates.

The Merger Agreement is attached to this information statement as Annex A and is incorporated herein by reference. MEP encourages you to read the Merger Agreement in its entirety because it is the legal document that governs the Merger. For more information regarding the terms of the Merger Agreement, see “The Merger Agreement.”

The Merger Consideration

Each Class A Common Unit issued and outstanding immediately prior to the Effective Time, other than Class A Common Units held by EECI, EEP and their respective affiliates, will be converted into the right to

 



 

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receive $8.00 in cash, without interest (the “Merger Consideration”). As of the Effective Time, each holder of Class A Common Units that is entitled to the Merger Consideration pursuant to the terms of the Merger Agreement (each, a “MEP Unaffiliated Unitholder”) will cease to have rights with respect to those Class A Common Units immediately prior to the Effective Time except the right to receive the Merger Consideration. The Merger Consideration is subject to adjustment pursuant to the terms of the Merger Agreement to reflect the effect of any unit dividend, subdivision, reclassification, recapitalization, split or similar transaction and to provide the MEP Unaffiliated Unitholders the same economic effect as contemplated by the Merger Agreement prior to any such event.

All of the limited liability company interests in Merger Sub issued and outstanding immediately prior to the Effective Time will be converted automatically into a number of newly issued Class A Common Units of MEP equal to the number of Class A Common Units converted into the right to receive the Merger Consideration (the “New Class A Common Units”). The general partner interest in MEP owned by MEP GP immediately prior to the Effective Time will be unaffected by the Merger and will remain outstanding. The incentive distribution rights in MEP owned by MEP GP and the MEP common units owned by EEP issued and outstanding as of immediately prior to the Effective Time will be unchanged and remain issued and outstanding in the surviving entity and no consideration will be delivered in respect of those rights or units. Any partnership interests in MEP (other than the general partner interest, the incentive distribution rights and the common units owned by EEP) that are owned immediately prior to the Effective Time by MEP or any subsidiary of MEP or by EECI or any affiliate of EECI will be automatically cancelled and cease to exist. No consideration will be delivered for such cancelled partnership interests. To the extent applicable, holders of Class A Common Units immediately prior to the Effective Time will have continued rights to any distribution, without interest, with respect to such Class A Common Units with a record date occurring prior to the Effective Time that has been declared by MEP GP with respect to such Class A Common Units in accordance with the terms of the Merger Agreement and which remains unpaid as of the Effective Time.

To the extent applicable, holders of Class A Common Units prior to the Effective Time (other than EEP) will have no rights to any distribution with respect to such Class A Common Units with a record date occurring on or after the Effective Time that may have been declared by MEP GP with respect to such Class A Common Units prior to the Effective Time and which remains unpaid as of the Effective Time.

For more information regarding the terms of the Merger Consideration, see “The Merger Agreement—The Merger Consideration.”

Effects of the Merger

If the Merger is completed, (1) MEP Unaffiliated Unitholders will no longer have an equity interest in MEP, (2) the Class A Common Units will no longer be listed on the NYSE, (3) the registration of the Class A Common Units under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), will be terminated and (4) EECI will own approximately 48% of the limited partner interests in MEP, and EEP will own the remaining approximate 52% of the limited partner interests and 2% general partner interest in MEP.

Information about the Action by Written Consent

Required Unitholder Approval

Under the applicable provisions of MEP’s First Amended and Restated Agreement of Limited Partnership, dated as of November 13, 2013, as amended from time to time (the “MEP Partnership Agreement”), the approval of the Merger Agreement requires the approval of a “Unit Majority” which, after the end of the subordination period, means at least a majority of the outstanding common units (the “Partnership Unitholder Approval”). The

 



 

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subordination period with respect to MEP subordinated units owned by EEP ended on February 15, 2017 after MEP paid its quarterly cash distribution for the quarter ended December 31, 2016, and the subordinated units were converted into common units on a one-for-one basis. As a result of such conversion, EEP owns approximately 52% of MEP’s outstanding common units, a sufficient number of common units to approve the Merger Agreement and the Merger Transactions on behalf of the holders of MEP common units. Concurrently with the execution of the Merger Agreement on January 26, 2017, MEP entered into a support agreement with EECI and EEP (the “Support Agreement”) whereby EEP has agreed, in its capacity as a unitholder of MEP, to vote its units in favor of the Merger Agreement and the Merger Transactions.

Immediately prior to the closing of the Merger Transactions, EEP will deliver to MEP a written consent approving the Merger Agreement and the Merger Transactions. As a result, MEP has not solicited and is not soliciting your approval of the Merger Agreement or the Merger Transactions. Further, MEP does not intend to call a meeting of unitholders for purposes of voting on the approval of the Merger Agreement or the Merger Transactions.

Recommendation of MEP GP Board and MEP Committee

On January 26, 2017, the conflicts committee (the “MEP Committee”) of the board of directors of MEP GP (the “MEP GP Board”), consisting of three independent directors, unanimously (1) determined that the Merger Agreement, the Support Agreement and the Merger Transactions are fair and reasonable to and in the best interests of MEP and its subsidiaries and the MEP Unaffiliated Unitholders, (2) approved the Merger Agreement, the Support Agreement and the Merger Transactions, (3) recommended that the MEP GP Board approve the Merger Agreement and the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement by MEP and the consummation of the Merger Transactions and (4) recommended that the MEP GP Board submit the Merger Agreement to a vote of MEP’s limited partners and recommend the approval of the Merger Agreement by MEP’s limited partners, such approvals by the MEP Committee constituting “Special Approval” as such term is defined in the MEP Partnership Agreement. The MEP Committee consulted with its financial and legal advisors and considered many factors in making its determinations, approvals and recommendations.

Acting based in part on the recommendation of the MEP Committee and after receiving the approval of MEP GP’s sole member, the MEP GP Board unanimously (1) determined that each of the Merger, the Merger Agreement, the Support Agreement and the Merger Transactions is fair and reasonable to and in the best interests of MEP and its subsidiaries and MEP’s limited partners, (2) approved the Merger Agreement, the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement and the consummation of the Merger Transactions, (3) resolved to submit the Merger Agreement to a vote of MEP’s limited partners by written consent, and (4) recommended approval of the Merger Agreement, including the Merger, by MEP’s limited partners.

See “Special Factors—Recommendation of the MEP Committee and the MEP GP Board; Reasons for Recommending Approval of the Merger Agreement and the Merger Transactions.”

Opinion of Evercore Group L.L.C. Financial Advisor to the MEP Committee

At the request of the MEP Committee at a meeting of the MEP Committee held on January 26, 2017, Evercore Group L.L.C. (“Evercore”) rendered its oral opinion to the MEP Committee that, as of January 26, 2017, based upon and subject to the factors, procedures, assumptions, qualifications, limitations and other matters set forth in the Written Opinion (defined below), the Merger Consideration provided for pursuant to the Merger Agreement is fair, from a financial point of view, to the MEP Unaffiliated Unitholders. Evercore subsequently confirmed its oral opinion in writing dated January 26, 2017 to the MEP Committee (the “Written Opinion”).

 



 

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Evercore’s opinion was directed to the MEP Committee (in its capacity as such), and only addressed the fairness from a financial point of view, as of the date of the opinion, to the MEP Unaffiliated Unitholders of the Merger Consideration provided for pursuant to the Merger Agreement. Evercore’s opinion did not address any other term or aspect of the Merger Agreement or the Merger Transactions. The full text of the Written Opinion, which describes the assumptions made, procedures followed, matters considered, and qualifications and limitations of the review undertaken by Evercore in rendering its opinion, is attached as Annex C to this information statement. The summary of Evercore’s opinion set forth in this information statement is qualified in its entirety by reference to the full text of the Written Opinion. However, neither the Written Opinion nor the summary of such opinion and the related analyses set forth in this information statement are intended to be, and they do not constitute, a recommendation as to how unitholders of MEP or any other person should act or vote with respect to any matter relating to the Merger Transactions or any other matter.

See “Special Factors— Opinion of Evercore Group L.L.C. – Financial Advisor to the MEP Committee.”

Support Agreement

On January 26, 2017, EECI, EEP and MEP entered into the Support Agreement, pursuant to which, among other things, EEP agreed, in its capacity as a unitholder of MEP, to vote (or cause to be voted) all of the common and subordinated units in MEP owned of record by EEP as of the date of the Support Agreement as well as any common units in MEP acquired beneficially or of record by EEP after the date of the Support Agreement (1) in favor of the approval and adoption of the Merger Agreement, the Merger Transactions and any other matter necessary for the consummation of such transactions submitted for the vote or written consent of the unitholders of MEP; (2) against any action or agreement that would result in a breach of any covenant, representation or warranty or any other obligation or agreement of MEP or MEP GP or any of their subsidiaries contained in the Merger Agreement; and (3) against any action, agreement or transaction that would impede, interfere with, delay, postpone or adversely affect the Merger Transactions.

The full text of the Support Agreement is attached to this information statement as Annex B. MEP encourages its unitholders to read the Support Agreement carefully and in its entirety.

EEM Conflicts Committee and the EEM Board

On January 26, 2017, the special committee (the “EEM Conflicts Committee”) of the board of directors of EEM (the “EEM Board”), (1) determined that each of the Merger Agreement and the Merger Transactions is fair and reasonable to, and in the best interests of, EEP including the holders of units of limited partner interests in EEP (other than EECI, EEM and their respective affiliates) (the “EEP Unaffiliated Unitholders”), (2) recommended, on behalf of EEP, that the EEM Board cause EEP to (A) approve the Merger and the Merger Transactions, (B) vote or deliver a written consent in respect of EEP’s limited partner interests in MEP in favor of the Merger and the Merger Transactions and (C) enter into the Support Agreement.

Acting in part based on the recommendation of the EEM Conflicts Committee, the EEM Board (1) determined that each of the Merger, the Merger Agreement and the Merger Transactions is fair and reasonable to and in the best interests of EEP, including its partners, (2) authorized and approved the voting or consent by EEP, (A) as the sole member of MEP GP and (B) of the Units held by EEP, in favor of the Merger and the adoption and approval of the Merger Agreement, and (3) authorized and approved the Support Agreement.

See “Special Factors—EEM Conflicts Committee and the EEM Board.”

 



 

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Interests of Certain Persons in the Merger

In considering the recommendations of the MEP GP Board and the MEP Committee with respect to the Merger, the MEP Unaffiliated Unitholders should be aware that certain of the executive officers and directors of MEP GP have interests in the transaction that differ from, or are in addition to, the interests of the MEP Unaffiliated Unitholders generally, including:

 

    certain executive officers of MEP GP hold unvested performance share units in MEP;

 

    certain directors and executive officers of MEP GP, some of whom are also directors and/or officers of EECI, own Class A Common Units that will be cancelled at the Effective Time of the Merger and converted into the right to receive the Merger Consideration;

 

    the chairman of the MEP Committee will receive $5,000 for his service as chairman of the MEP Committee and each member of the MEP Committee will receive a fee of $1,500 per meeting;

 

    each member of the MEP Committee will receive a reasonable hourly fee for time spent in connection with litigation arising out of their service on the MEP Committee, in addition to any other compensation they receive for service on the MEP GP Board and its committees; and

 

    all of the directors and executive officers of MEP GP will receive continued indemnification for their actions as directors and executive officers after the Effective Time of the Merger.

These arrangements are more fully described under “Special Factors—Interests of Certain Persons in the Merger.”

Regulatory Approvals Required for the Merger

Neither MEP nor any of the Enbridge Parties (as defined below) is aware of any federal or state regulatory approval required in connection with the Merger, other than compliance with relevant federal securities laws.

Conditions to Completion of the Merger

Before the Merger can be completed, a number of conditions set forth in the Merger Agreement must be satisfied or waived. These include:

 

    with respect to any party’s obligation to effect the Merger, the Partnership Unitholder Approval has been obtained;

 

    with respect to any party’s obligation to effect the Merger, the absence of any legal restraint or prohibition enjoining or otherwise prohibiting the consummation of the Merger or making the consummation of the Merger illegal;

 

    with respect to EECI’s and Merger Sub’s obligation to effect the Merger, MEP’s and MEP GP’s representations and warranties are accurate, subject to materiality qualifications;

 

    with respect to MEP’s and MEP GP’s obligation to effect the Merger, EECI’s and Merger Sub’s representations and warranties are accurate, subject to materiality qualifications; and

 

    each of the parties has performed their respective obligations, and each of the parties has complied with their respective covenants, subject to materiality qualifications.

MEP can give no assurance when or if all of the conditions to the Merger will be either satisfied or, to the extent possible, waived, or that the Merger will be consummated. For more information, see “The Merger Agreement—Conditions to Completion of the Merger.”

 



 

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Termination of the Merger Agreement

The Merger Agreement may be terminated and the Merger may be abandoned at any time prior to the Effective Time, whether before or after MEP’s unitholders approve the Merger Agreement and the Merger Transactions:

 

    by the mutual written consent of MEP and EECI duly authorized by the MEP GP Board, after consulting with the MEP Committee, and the board of directors of EECI;

 

    by either MEP (duly authorized by the MEP GP Board after consulting with the MEP Committee) or EECI, if:

 

    the closing of the Merger does not occur on or before June 30, 2017 (the “Outside Date”), except that the right to terminate the Merger Agreement will not be available (1) to MEP if the failure to satisfy such condition is due to the failure of MEP or MEP GP to perform and comply in all material respects with the covenants and agreements to be performed or complied with by it before the closing of the Merger, (2) to EECI if the failure to satisfy such condition is due to the failure of EECI, Merger Sub or EEP to perform and comply in all material respects with the covenants and agreements contained in the Merger Agreement or the Support Agreement, as applicable, to be complied with by them before the closing of the Merger or (3) to MEP or EECI if, in the case of EECI, MEP or MEP GP, and in the case of MEP, EECI or Merger Sub, has filed (and is then pursuing) an action seeking specific performance as permitted by the Merger Agreement; or

 

    any restraint is in effect and has become final and nonappealable that has the effect of enjoining, restraining, preventing or prohibiting the consummation of the Merger Transactions or making the consummation of the Merger Transactions illegal, except that the right to terminate the Merger Agreement will not be available to MEP or EECI if the restraint was due to the failure of, in the case of MEP, MEP or MEP GP, and in the case of EECI, Merger Sub or EEP, to perform in all material respects any of its obligations under the Merger Agreement or the Support Agreement, as applicable;

 

    MEP or MEP GP (1) withdraws, modifies or qualifies, or proposes to withdraw, modify or qualify, in a manner adverse to EECI, the recommendation of MEP (through the MEP GP Board’s recommendation) that MEP’s limited partners approve the Merger Agreement (the “Partnership Board Recommendation”) or (2) fails to include the Partnership Board Recommendation in this information statement (the circumstances described in (1) and (2), each a “MEP Adverse Recommendation Change”);

 

    by EECI, if:

 

    MEP, prior to obtaining the Partnership Unitholder Approval, is in willful breach of its obligations relating to the MEP Board Recommendation or the MEP Adverse Recommendation Change; provided that EECI will not have the right to terminate the Merger Agreement under this condition if EECI, Merger Sub or EEP is then in material breach of any of its representations, warranties, covenants or agreements contained in the Merger Agreement or the Support Agreement, as applicable; or

 

    MEP or MEP GP has breached or failed to perform any of its representations, warranties, covenants or agreements contained in the Merger Agreement if the breach or failure to perform (1) would constitute the failure of a condition to EECI’s obligation to complete the Merger and (2) is not capable of being cured, or is not cured, by MEP or MEP GP within the earlier of (A) 30 days after receipt of EECI’s notice of such breach or failure or (B) the Outside Date; provided that EECI will not have the right to terminate the Merger Agreement under this condition if EECI, Merger Sub or EEP is then in material breach of any of its representations, warranties, covenants or agreements contained in the Merger Agreement or the Support Agreement, as applicable;

 



 

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    by MEP (duly authorized by the MEP GP Board after consulting with the MEP Committee), if EECI or Merger Sub has breached or failed to perform any of its representations, warranties, covenants or agreements contained in the Merger Agreement or if any of EECI’s or Merger Sub’s representations or warranties contained in the Merger Agreement fails to be true and such breach or failure would (1) constitute the failure of a condition of MEP’s obligation to complete the Merger and (2) is not capable of being cured, or is not cured, by EECI or Merger Sub within the earlier of (A) 30 days after receipt of MEP’s notice of such breach or failure or (B) the Outside Date; provided that MEP will not have the right to terminate the Merger Agreement if MEP or MEP GP is then in material breach of any of its representations, warranties, covenants or agreements contained in the Merger Agreement.

For more information regarding the termination of the Merger Agreement, see “The Merger Agreement—Termination.”

Effect of Termination; Remedies

In the event of termination of the Merger Agreement as summarized above under “—Termination of the Merger Agreement,” the Merger Agreement will terminate, except for certain provisions, and there will be no liability on the part of any of EECI and or MEP and MEP GP or their respective directors, officers and affiliates to the other parties except for any failure to consummate the Merger and the Merger Transactions when required pursuant to the Merger Agreement except in the case of a party’s intentional and material breach of the Merger Agreement or intentional fraud, in which case the other applicable party or parties will be entitled to pursue any and all legally available remedies, including equitable relief, and to seek recovery of all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees and time value of money).

For more information regarding the effect of termination and remedies, see “The Merger Agreement—Effect of Termination; Remedies.”

Expenses Relating to the Merger

Generally, each party to the Merger Agreement is responsible for its own expenses, including the fees and expenses of its advisors.

Financing of the Merger

The total amount of funds necessary for EECI to consummate the Merger and the Merger Transactions is anticipated to be approximately $170,200,000. EECI expects to fund the Merger through an intercompany financing from a wholly owned direct or indirect subsidiary of Enbridge.

See “Special Factors—Financing of the Merger.”

Material U.S. Federal Income Tax Considerations

The receipt of cash in exchange for Class A Common Units pursuant to the Merger will be a taxable transaction for U.S. federal income tax purposes to holders. A holder who receives cash in exchange for Class A Common Units pursuant to the Merger will recognize gain or loss in an amount equal to the difference between:

 

    the sum of (1) the amount of any cash received and (2) such holder’s share of MEP’s nonrecourse liabilities immediately prior to the Merger; and

 

    such holder’s adjusted tax basis in the Class A Common Units exchanged therefor (which includes such holder’s share of MEP’s nonrecourse liabilities immediately prior to the Merger).

 



 

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Gain or loss recognized by a holder will generally be taxable as capital gain or loss. However, a portion of this gain or loss, which could be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code of 1986, as amended (the “Code”) to the extent attributable to assets giving rise to “unrealized receivables, ” including depreciation recapture, or to substantially appreciated “inventory items” owned by MEP and its subsidiaries. Passive losses that were not deductible by a holder in prior taxable periods because they exceeded such holder’s share of MEP’s income may become available to offset a portion of the gain recognized by such holder.

The U.S. federal income tax consequences of the Merger to a holder of Class A Common Units will depend on such unitholder’s own personal tax situation. Accordingly, we strongly urge you to consult your tax advisor for a full understanding of the particular tax consequences of the Merger to you.

Please read “Material U.S. Federal Income Tax Considerations” for a more complete discussion of certain U.S. federal income tax consequences of the Merger.

No Appraisal Rights

Holders of Class A Common Units are not entitled to dissenters’ rights of appraisal under the MEP Partnership Agreement, the Merger Agreement or applicable Delaware law.

See “Special Factors—No Appraisal Rights.”

Accounting Treatment

The Merger will be accounted for in accordance with generally accepted accounting principles in the United States of America (“GAAP”). As EECI, through its direct and indirect interest through EEP, will have a controlling financial interest in MEP, both before and after the Merger, changes in its ownership interest in MEP will be accounted for as an equity transaction and no gain or loss on the Merger will be recognized in its consolidated statements of earnings.

See “Special Factors—Accounting Treatment of the Merger.”

Delisting and Deregistration of Class A Common Units

Upon completion of the Merger, the Class A Common Units will cease to be listed on the NYSE and will be subsequently deregistered under the Exchange Act.

See “Delisting and Deregistration of Class A Common Units.”

 



 

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QUESTIONS AND ANSWERS ABOUT THE MERGER

 

Q: Why am I receiving these materials?

 

A: This information statement describes the Merger and the approval of the Merger Agreement and the Merger Transactions by written consent of our unitholders. The MEP GP Board is providing this information statement to you pursuant to Section 14(c) of the Exchange Act solely to inform you of, and provide you with information about, the Merger and the Merger Transactions before the Merger is consummated. This information statement is first being mailed to holders of Class A Common Units (the “MEP Common Unitholders”) on or about April 7, 2017.

 

Q: Why am I not being asked to vote on the Merger?

 

A: Consummation of the Merger requires Partnership Unitholder Approval. EEP owns approximately 52% of MEP’s common units, a sufficient number to approve the Merger Agreement and Merger Transactions on behalf of the MEP Common Unitholders. Concurrently with the execution of the Merger Agreement, EECI, EEP and MEP entered into the Support Agreement whereby EEP agreed to vote its MEP common units in favor of the Merger Agreement and Merger Transactions. EEP will deliver a written consent approving the Merger Agreement and the Merger Transactions immediately prior to the closing of the Merger Transactions. As a result, MEP has not solicited and is not soliciting your approval of the Merger Agreement or Merger Transactions, and does not plan to call a meeting of unitholders to approve the Merger Agreement or Merger Transactions.

 

Q: What will happen in the Merger?

 

A: Merger Sub will merge with and into MEP, with MEP surviving the Merger and continuing to exist as a Delaware limited partnership.

 

Q: What will I, as a holder of Class A Common Units, receive if the Merger is completed?

 

A: Upon completion of the Merger, you will be entitled to receive $8.00 per Class A Common Unit in cash, without interest, less any applicable withholding taxes.

See “The Merger Agreement—The Merger Consideration.”

 

Q: Will MEP continue to pay quarterly distributions?

Holders of Class A Common Units will be entitled to any distributions declared by MEP GP and paid by MEP with respect to the Class A Common Units that have a record date occurring prior to the Effective Time, but MEP GP has not announced any future distributions and is under no obligation to do so.

 

Q: What will holders of MEP incentive awards receive in the Merger?

 

A: MEP GP has not previously granted any equity incentive awards in MEP. However, certain executive officers of MEP GP and other key employees who provide services to MEP GP have previously been granted performance share units in MEP that, if earned based on MEP’s performance against certain pre-established metrics, represent the right to receive a cash payment based upon the trading price of MEP common units (the “MEP PSUs”). MEP GP and EECI have determined that upon consummation of the Merger, the MEP PSU performance metrics will be frozen and the cash payment due upon vesting on the original maturity date will be based on the $8.00 per unit merger consideration with a potential additional amount that will fluctuate with total shareholder return corresponding to an investment in Enbridge over the remainder of the applicable vesting period.

See “Special Factors—Interests of Certain Persons in the Merger.”

 

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Q: How does the $8.00 per unit Merger Consideration compare to the market price of Class A Common Units prior to the execution of the Merger Agreement?

 

A: The $8.00 per unit Merger Consideration represents a premium of approximately 5.5% to the 30-day volume-weighted average closing price (“VWAP”) of Class A Common Units as of January 26, 2017, the last trading day prior to the public announcement the Merger Agreement. The $8.00 per unit Merger Consideration is below the closing price of the Class A Common Units as of January 26, 2017. During the period beginning December 5, 2016, the date on which EECI made its initial proposal of $6.25 per Class A Common Unit to the MEP GP Board, and January 26, 2017, the date the Merger Agreement was approved and executed, there was a large and unexpected increase in the market price of Class A Common Units. The market price of Class A Common Units increased by 39.2% during this period, compared to an increase of 10.7% in the price of a basket of securities of peer group master limited partnerships (“MLP”s). There were no changes in MEP’s underlying business or financial condition to support such an increase in the market price of Class A Common Units. During this time, MEP continued to face a continued declining financial condition. As a result, EECI was not willing to pay more than $8.00 per Class A Common Unit, which EECI already believed was far in excess of the underlying value of MEP’s distressed business.

 

Q: Why does the MEP GP Board recommend that unitholders approve the Merger Agreement and Merger Transactions?

 

A: The MEP GP Board considered a number of factors in making its determination and approvals and the related recommendation to the holders of Class A Common Units. The factors considered by the MEP GP Board to be generally positive or favorable include, but are not limited to, the following:

 

    the unanimous determination and recommendation of the MEP Committee;

 

    receipt by the MEP Committee of the opinion of Evercore, dated January 26, 2017, that based upon and subject to the factors, procedures, assumptions, qualifications, limitations and other matters set forth therein, as of January 26, 2017, the $8.00 per unit Merger Consideration to be received by the MEP Unaffiliated Unitholders in connection with the Merger was fair, from a financial point of view, to the MEP Unaffiliated Unitholders;

 

    the Merger would provide the MEP Unaffiliated Unitholders with Merger Consideration of $8.00 per Class A Common Unit, a price the MEP Committee viewed as fair in light of MEP’s recent and projected financial performance. Such consideration amount represented a premium of approximately 5.5% above the VWAP of a Class A Common Unit for the 30 consecutive NYSE full trading days ending at the close of regular trading hours on the NYSE on January 26, 2017 (the last trading day before the announcement of the Merger Agreement and the Merger Transactions);

 

    the Merger Consideration of $8.00 per Class A Common Unit represents a 28% increase from the value of the total consideration originally offered by EECI as part of the Merger Agreement and the Merger Transactions;

 

    The MEP Committee’s belief that Enbridge’s alternative offers of merger consideration per Class A Common Unit of either (i) $7.80 per Class A Common Unit or (ii) the current trading price of the Class A Common Units at the execution of the Merger Agreement not to exceed $7.90 or be below $7.70, was its final offer and the conclusion reached by the MEP Committee that $8.00 per Class A Common Unit was likely the highest amount of consideration that Enbridge would be willing to pay at the time of the MEP Committee’s determination and approval;

 

    the MEP Committee’s belief that, under the status quo, the MEP Unaffiliated Unitholders would experience significant dilution as a result of MEP’s efforts to maintain compliance with the Loan Documents (defined below in “Special Factors—Background of the Merger”) financial covenants as detailed by Enbridge on the morning of January 25, 2017 and that the Class A Common Unit market price would significantly decline if the distribution was reduced or eliminated; and

 

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    the MEP Committee’s belief that it was unlikely that any other transaction with a third party involving a sale of MEP or significant interest in MEP or its assets could be consummated at the time of the MEP Committee’s determination and approval in light of (1) the results of the Sale Process (defined below in “Special Factors—Background of the Merger”) and (2) Enbridge’s position stated in its proposal, dated December 5, 2016, that it was only interested in acquiring all of the outstanding Class A Common Units owned by the MEP Unaffiliated Unitholders and had no interest in approving any combination of MEP with, or a sale of all or substantially all of the assets of MEP to, any other acquirer.

For a full list of the factors considered by the MEP GP Board and the MEP Committee, please see “Special Factors—Recommendation of the MEP Committee and the MEP GP Board; Reasons for Recommending Approval of the Merger Agreement and the Merger Transactions.”

 

Q: When do you expect the Merger to be completed?

 

A: MEP and EECI are working towards completing the Merger as soon as possible. Assuming timely satisfaction of other closing conditions, MEP currently anticipates that the Merger will be completed in the second quarter of 2017.

See “The Merger Agreement—Effective Time; Closing.”

 

Q: What if the Merger is not completed?

 

A: If the Merger Agreement and the Merger Transactions do not receive Partnership Unitholder Approval or if the Merger is not completed for any other reason, you will not receive any consideration for your Class A Common Units in connection with the Merger. Instead, MEP will remain an independent, publicly traded MLP, and Class A Common Units will continue to be listed and traded on the NYSE.

 

Q: What conditions must be satisfied to complete the Merger?

 

A: EECI and MEP are not required to complete the Merger unless a number of conditions are satisfied or waived. These conditions include, among others, the receipt of Partnership Unitholder Approval of the Merger Agreement and the Merger Transactions. Following the termination of the subordination period on February 15, 2017, as described above, EEP owns approximately 52% of MEP’s outstanding common units, a sufficient number to approve the Merger Agreement and Merger Transactions on behalf of the MEP Common Unitholders. EEP agreed to vote its MEP common units in favor of the Merger Agreement and Merger Transactions pursuant to the Support Agreement, and EEP will deliver a written consent approving the Merger Agreement and the Merger Transactions immediately prior to the closing of the Merger Transactions, which will satisfy the condition of the receipt of Partnership Unitholder Approval of the Merger Agreement and the Merger Transactions.

For a more complete summary of the conditions that must be satisfied or waived prior to the completion of the Merger, see “The Merger Agreement—Conditions to Completion of the Merger.”

 

Q: Why is there no vote required if Partnership Unitholder Approval is required to approve of the Merger Agreement and the Merger Transactions?

 

A: Approval of the Merger Agreement and the Merger Transactions requires Partnership Unitholder Approval. The MEP Partnership Agreement permits voting by written consent. EEP owns approximately 52% of the outstanding Class A Common Units, a sufficient number to approve the Merger Agreement and Merger Transactions. Pursuant to the Support Agreement, EEP will execute and deliver a written consent, immediately prior to the closing of the Merger Transactions, approving the Merger Agreement and Merger Transactions, which consent will constitute Partnership Unitholder Approval.

See “Summary Term Sheet—Information about the Action by Written Consent.”

 

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Q: Will MEP be required to submit the Merger Agreement and the Merger Transactions to MEP Common Unitholders even if the MEP GP Board has effected a change of recommendation that MEP Common Unitholders adopt the Merger Agreement?

 

A: Yes. Unless the Merger Agreement is terminated, MEP is required to submit the Merger Agreement and the Merger Transactions to MEP Common Unitholders regardless of whether the MEP GP Board recommends that MEP Common Unitholders reject the Merger Agreement and the Merger Transactions or otherwise takes any action constituting a “Partnership Adverse Recommendation Change” under the Merger Agreement.

For more information regarding the ability of MEP to terminate the Merger Agreement, and the MEP Committee’s ability to change its recommendation with respect to the Merger Agreement and the Merger Transactions, see “The Merger Agreement—Termination” and “The Merger Agreement—MEP GP Recommendation and MEP Adverse Recommendation Change.”

 

Q: What do I need to do now?

 

A: No action by you is requested or required at this time. If the Merger is consummated, you will receive instructions regarding the surrender of your Class A Common Units and payment for your Class A Common Units.

 

Q: What happens if I sell my Class A Common Units before the Effective Time?

 

A: If you transfer your Class A Common Units before the Effective Time, you will transfer the right to receive the per unit Merger Consideration if the Merger is consummated to the person to whom you transfer your Class A Common Units.

See “Summary Term Sheet—Information about the Action by Written Consent.”

 

Q: How will I receive the per unit Merger Consideration to which I am entitled?

 

A: Promptly after the Effective Time, the paying agent, Computershare Trustee Company N.A., will mail or provide to each holder of record of Class A Common Units certain transmittal materials and instructions for use in effecting the surrender of Class A Common Units to the paying agent. If you hold a unit certificate, please do not send it to the paying agent until you receive these transmittal materials and instructions. If your Class A Common Units are held in “street name” through a bank, brokerage firm or other nominee, you should contact your bank, brokerage firm or other nominee for instructions as to how to effect the surrender of your “street name” Class A Common Units in exchange for the per unit Merger Consideration.

See “The Merger Agreement—Surrender of Class A Common Units.”

 

Q: Am I entitled to appraisal or dissenters’ rights?

 

A: No. Holders of Class A Common Units are not entitled to dissenters’ rights of appraisal under the MEP Partnership Agreement, the Merger Agreement or applicable Delaware law.

 

Q: What are the expected U.S. federal income tax consequences to a holder of Class A Common Units as a result of the Merger?

 

A:

The receipt of cash in exchange for Class A Common Units pursuant to the Merger will be a taxable transaction for U.S. federal income tax purposes. A holder will generally recognize capital gain or loss on the receipt of cash in exchange for Class A Common Units. However, a portion of this gain or loss, which could be substantial, will be separately computed and taxed as ordinary income or loss to the extent attributable to assets giving rise to “unrealized receivables,” including depreciation recapture, or to

 

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  “inventory items” owned by MEP and its subsidiaries. Passive losses that were not deductible by a holder in prior taxable periods because they exceeded a holder’s share of MEP’s income may become available to offset a portion of the gain recognized by such holder. The U.S. federal income tax consequences of the Merger to a holder of Class A Common Units will depend on such unitholder’s own personal tax situation. Accordingly, we strongly urge you to consult your tax advisor for a full understanding of the particular tax consequences of the Merger to you.

See “Material U.S. Federal Income Tax Considerations” for a more complete discussion of certain U.S. federal income tax consequences of the Merger.

 

Q: What is “householding”?

 

A: The SEC has adopted rules that permit companies and intermediaries (such as brokers or banks) to satisfy the delivery requirements for information statements with respect to two or more security holders sharing the same address by delivering a single notice or information statement addressed to those security holders. This process, which is commonly referred to as “householding”, potentially provides extra convenience for security holders and cost savings for companies.

Banks, brokers and other nominees with accountholders who are MEP Common Unitholders may be “householding” MEP’s information statement materials. As indicated in the notice provided by these brokers to MEP Common Unitholders, a single information statement will be delivered to multiple unitholders sharing an address unless contrary instructions have been received from an affected MEP Common Unitholder. Once you have received notice from your broker that it will be “householding” communications to your address, “householding” will continue until you are notified otherwise or until you revoke your consent. If, at any time, you no longer wish to participate in “householding” and you prefer to receive a separate information statement, please notify your broker or write to the following address:

Midcoast Energy Partners, L.P.

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

Attention: Investor Relations

Telephone: (713) 821-2000

 

Q: Who can help answer my questions?

 

A: If you have any questions about the Merger or need additional copies of this information statement, you should contact MEP at the above address and phone number.

 

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SPECIAL FACTORS

This discussion of the Merger is qualified by reference to the Merger Agreement, which is attached to this information statement as Annex A. You should read the entire Merger Agreement carefully because it is the legal document that governs the Merger.

If the Merger is completed, the holders of the Class A Common Units will have the right to receive the Merger Consideration, less any applicable withholding taxes.

Background of the Merger

The senior management teams and boards of directors of Enbridge, MEP, EEP and EEM regularly review operational and strategic opportunities to maximize value for their respective investors. In connection with these reviews, these management teams and boards of directors from time to time evaluate potential transactions that would further their respective strategic objectives.

As more fully described in the Section entitled “Summary Term Sheet—Parties to the Merger—Relationship Between the Parties,” MEP was formed by EEP to serve as EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. MEP is managed and operated by the board of directors and executive officers of MEP GP. EEP is the sole owner of MEP GP and has the right to appoint the entire MEP GP Board, including the independent directors appointed in accordance with the listing standards of the NYSE. Through a delegation of control agreement, EEP’s general partner, EECI, has delegated to EEM the authority to manage and control EEP’s business and affairs. Through its indirect ownership of EEM’s voting shares, EECI controls EEM and appoints all of its directors. EECI is an indirect wholly owned subsidiary of Enbridge, and Enbridge has the right to appoint all of EECI’s directors.

Demand for MEP’s midstream services primarily depends upon the supply of natural gas, NGLs and associated natural gas from crude oil development, as well as the drilling rate for new wells. Demand for these services depends on overall economic conditions and commodity prices. Since 2015, commodity prices for natural gas, NGLs, condensate and crude oil have remained low. As a result, there has been reduced drilling activity and declining volumes in the basins in which MEP operates as compared to other basins such as the Marcellus, Utica and Permian, which are viewed as more economic in the current commodity price environment. Due to the commodity price environment, MEP expects drilling activity to remain low and, as a result, MEP expects to see continued low volumes on its systems in 2017 and beyond. While MEP has a hedging program in place to assist in mitigating its direct commodity risk, (1) MEP’s condensate hedge prices for 2017 are approximately 20% lower than 2016 and (2) MEP’s NGL hedge prices for 2017 are on average 30% lower than 2016. Despite its hedging program, MEP continues to bear direct commodity price exposure for unhedged commodity positions as well as indirect commodity price exposure as lower drilling activity impacts the volumes on its systems.

Low commodity prices and the resultant decreased drilling activity and declining volumes in the basins in which MEP operates have had an adverse impact on MEP’s financial condition, results of operations and cash flows. These adverse impacts are expected to worsen in 2017 and through 2019 which, absent affirmative steps to address such matters, would materially and adversely affect MEP’s distribution coverage and its ability to comply with its existing credit agreement covenants. MEP’s projected operational and financial performance is expected to necessitate, among other things, (1) a significant reduction in or elimination of MEP’s quarterly distributions and (2) significant equity infusions by EEP that would be expected to be materially dilutive to existing MEP unitholders. MEP’s projected Adjusted EBITDA for 2017 is $50.6 million, a 41% decrease from 2016. In addition, MEP’s projected ratio of net debt to Adjusted EBITDA is expected to be 8.9x in 2017, which would result in a breach of the related covenants under the Loan Documents (defined below). MEP did not pursue a modification of the covenants in the Loan Documents or a waiver for the potential breach of covenants.

 

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On May 11, 2015, Citigroup Global Markets, Inc. (“Citi”) was formally engaged by EEP to evaluate and/or implement various strategic or financial alternatives regarding MEP. At a meeting of the MEP GP Board on June 25, 2015, the MEP GP Board established a special committee of independent directors, consisting of John A. Crum, James G. Ivey and Edmund P. Segner III, with Mr. Segner to serve as Chairman, to evaluate an expected proposal to be received from EEP regarding strategic and/or financial transactions with MEP.

In order to address MEP’s likely inability to maintain a 1.0x distribution coverage ratio, on July 15, 2015, EEM delivered a letter to the special committee proposing an amendment (the “MOLP Amendment”) to the Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P. (“MOLP”) that would adjust the allocation of cash distributions between MEP and EEP under such agreement for a period of time commencing with the quarter ending June 30, 2015 and continuing through and including the quarter ending December 31, 2017. Pursuant to the MOLP Amendment, during the applicable period and so long as MEP and EEP are the sole limited partners of MOLP, if MEP has a distribution coverage ratio that is less than 1.0x in a particular quarter, then the distribution payable to EEP for such quarter will be reduced and the distribution payable to MEP will be increased by an amount, up to 100% of EEP’s pro rata share of the limited partner distribution amount for such quarter, that is needed for MEP to achieve a 1.0x distribution coverage ratio. However, the MOLP Amendment does not require MEP to make any cash distributions on the Class A Common Units.

On July 23, 2015, the special committee approved the entry into the MOLP Amendment by MEP and Midcoast OLP GP, LLC, the general partner of MOLP (“MOLP GP”), and on July 29, 2015, the MOLP Amendment was executed by the MOLP GP, MEP and EEP. At that time, MEP believed its financial condition would improve beginning in 2018, and that the MOLP Amendment would be sufficient to address the concerns regarding MEP’s distribution coverage. The cash redistribution feature of the MOLP Amendment has taken effect in several quarters since the agreement became effective in July 2015, resulting in MEP receiving approximately $15.9 million in incremental cash distributions from MOLP.

In early 2016, in light of the continued commodity price downturn, reduced drilling activity and declining volumes on MEP’s system, management of Enbridge and EEP considered and discussed with the board of directors of Enbridge (the “Enbridge Board”) potential strategic alternatives with respect to MEP.

On February 17, 2016, at a meeting of the Enbridge Board, Enbridge’s management discussed Enbridge’s overall strategy regarding its U.S. sponsored vehicles, with a particular focus on the challenges facing the gathering and processing business. Enbridge’s management discussed various strategies to address these challenges, but no formal recommendation was made to the Enbridge Board at that time.

On April 22, 2016, at a meeting of the Enbridge Board, Enbridge’s management provided an update to the board of directors on Enbridge’s U.S. sponsored vehicle strategy. The Enbridge Board, acting on behalf of Enbridge as the controlling unitholder of EEP, took no exception to EEP commencing a private sale process of the U.S. gathering and processing business.

On May 2, 2016, MEP announced that, in light of the low commodity price environment and the ongoing challenges it presented to MEP’s business, MEP had begun working with EEP to explore and evaluate a broad range of strategic alternatives to address the challenges faced in their jointly owned gas business. As part of this review, EEP indicated that it was considering strategic alternatives with respect to its investment in MOLP and MEP. The various strategic alternatives that were evaluated included (i) asset sales, (ii) mergers, (iii) joint ventures, (iv) reorganizations or recapitalizations and (v) further reductions in operating and capital expenditures. MEP considered various asset sale and third-party merger transactions in connection with the Sale Process described below.

On May 19, 2016, EEM delivered a letter to the special committee proposing an equity commitment program (the “Equity Commitment”) pursuant to which EEP would purchase up to $250 million of a new class of equity securities in MEP (the “Class C Units”) pursuant to a subscription agreement between MEP and EEP (the

 

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“Subscription Agreement”). The Equity Commitment was proposed by EEP as a measure to enable MEP and MOLP to remain in compliance with the financial covenant leverage threshold (the “Total Leverage Ratio”) under the terms of the Credit Agreement, dated November 13, 2013, among MEP, MOLP and the lenders and other parties thereto (as amended, the “Credit Agreement”), and the Note Purchase Agreement, dated September 30, 2014, among MEP and the purchasers party thereto (the “Note Purchase Agreement” and, together with the Credit Agreement, the “Loan Documents”). The Total Leverage Ratio measures MEP’s total debt compared to EBITDA generated by its gas gathering and processing business. Under the terms of the Credit Agreement, if the Total Leverage Ratio exceeds 4.25 times for two consecutive quarters, a springing lien is triggered over MEP’s gas gathering and processing assets, and if liens are granted under the Credit Agreement, the Notes issued pursuant to the Note Purchase Agreement must also be equally secured. If the Total Leverage Ratio is in excess of 5.0 times, MEP’s total debt outstanding under the Loan Documents may become accelerated.

On May 25, 2016, Citi was formally engaged by Enbridge as financial advisor in connection with a potential transaction involving MOLP and MEP.

In considering the Equity Commitment, the special committee reviewed MEP’s financial condition and forecasted performance at the time with its legal and financial advisor. The special committee also considered that, when considering both the projections provided by management of MEP and the forward curve pricing forecasts, (1) MEP’s Total Leverage Ratio was projected at the time to exceed 4.25 times beginning in the third quarter of 2016 and continuing through 2019, which would trigger the springing lien, and (2) MEP’s Total Leverage Ratio was projected at the time to exceed 5.0 times beginning in the fourth quarter of 2016 and continuing through the fourth quarter of 2017, which, unless MEP’s debt was reduced using the proceeds of equity contributions to MEP, would permit the note holders or the lenders to accelerate MEP’s total outstanding debt under the Note Purchase Agreement or the Credit Agreement, respectively.

The special committee and EEM negotiated the terms of the Subscription Agreement and of the Class C Units such that, on a quarterly basis over a period of four quarters, MEP would evaluate the need for and the special committee would approve or disapprove, in its discretion, the purchase by EEP of Class C Units in an amount not to exceed $250 million at a price equal to 92% of the 5 trading day VWAP of the Class A Common Units as of the last trading day prior to the issuance date. The Class C Units would receive distributions as if they were Class A Common Units, except that any distribution on the Class C Units would be paid in kind in the form of additional Class C Units. The Class C Units would be convertible into Class A Common Units on a one-for-one basis at the sole option of the holder at any time on or after the occurrence of the earlier of (1) a change of control of MEP or (2) January 1, 2019. Each Class C Unit would have a liquidation preference over the other equity interests of MEP equal to the purchase price for such unit. Following negotiation between the special committee and EEM, on July 11, 2016, the special committee approved the entry by MEP into the Subscription Agreement. At a meeting of the MEP GP Board on July 11, 2016, the MEP GP Board similarly approved the Subscription Agreement but determined to delay execution of the documents related to the Subscription Agreement while certain strategic options were reviewed. Therefore, the Subscription Agreement was never executed.

During the following months, with the assistance of Citi, EEP conducted a process (the “Sale Process”) pursuant to which it marketed for sale all of its ownership interest in MEP GP and all of its limited partner interests in MEP and MOLP (collectively, the “EEP Interests”) or, alternatively, all of the general partner and limited partner interests in MEP and MOLP (the “Sale Process Transaction”). EEP determined to initiate the Sale Process given the overall financial issues facing MEP. Although MEP’s efforts over the preceding months to reduce operating and capital expenditures had resulted in savings that improved MEP’s financial condition, the savings were not enough to remedy MEP’s overall financial decline. Further reductions in operating and capital expenditures in addition to those already made would likewise not be sufficient. EEP also determined to proceed with the Sale Process prior to pursuing a recapitalization of MEP pursuant to the terms of the Subscription Agreement as it was determined that the required level of equity issuances to recapitalize MEP would result in severe dilution of MEP’s existing unitholders while not being sufficient to alleviate MEP’s expected covenant

 

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compliance issues. As part of the Sale Process, the potential buyer would be required to assume, guarantee or restructure obligations under the Loan Documents. EEP also indicated to participants in the Sale Process that it was open to alternative transactions that would maximize unitholder value, and EEP considered various asset sale and third-party merger transactions in connection with the Sale Process, as described below. However, no joint ventures were proposed by participants in the Sale Process, and EEP did not separately pursue any third-party joint venture transactions.

As part of the Sale Process, Citi, on behalf of EEP, contacted 67 parties representing a mix of strategic and financial buyers to gauge interest in the Sale Process Transaction. Of the 67 parties contacted, 34 executed non-disclosure agreements and received the confidential information memorandum presenting the Sale Process Transaction. Citi received initial, non-binding indications of interest for potential transactions from only four participants, two that conformed to the Sale Process Transaction and two that were indications of interest for alternative transactions. These four indications of interests are described in more detail below. EEP and Citi worked with the four potential buyers to vet their indications of interest and, ultimately, EEP determined that none of the indications of interest received provided the basis for consummating a transaction in which EEP was willing to participate at that time.

On June 21, 2016, EEP received a non-binding proposal from Company A. Company A proposed to acquire, subject to due diligence and other terms and conditions set forth in the proposal, the EEP Interests and assume, guarantee or restructure MEP’s outstanding debt. Alternatively, Company A proposed to acquire MOLP’s 35% interest in Texas Express Pipeline, LLC and Texas Express Gathering, LLC (collectively, “Texas Express”). Pursuant to the alternative proposal, Company A would assume MOLP’s portion of the take-or-pay obligations of Texas Express. Company A then separately communicated to Enbridge that Company A viewed its alternative proposal with respect to Texas Express as its preferred transaction. As a result, Enbridge and MEP focused exclusively on the alternative proposal.

On September 30, 2016, MOLP responded to Company A’s June 21, 2016 letter, and proposed that Company A acquire MOLP’s 35% interest in Texas Express.

On November 11, 2016, Company A revised its offer for MOLP’s 35% in Texas Express. The price set forth in Company A’s revised offer was not acceptable to EEP, as such price was below what EEP management had expected, and the parties did not exchange additional proposals. Enbridge and EEP management also determined that piecemeal sales of single assets were unlikely to fix the problems associated with MEP’s financial condition and focused primarily on transactions that presented a comprehensive solution to MEP’s financial condition.

On June 22, 2016, EEP received a non-binding proposal from Company B. Company B’s proposal contemplated a transaction pursuant to which EEP would drop down its interest in MOLP to MEP in exchange for MEP common units. MEP would then merge with and into Company B, with Company B issuing Company B common units as consideration. The Company B offer was rejected by EEP because the implied price was not acceptable to EEP and there was concern over accepting equity in Company B, which was not investment grade, as merger consideration.

On June 22, 2016, EEP received a non-binding proposal from Company C. Company C’s proposal contemplated a transaction pursuant to which MOLP would swap its 35% interest in Texas Express, together with certain other assets, to Company C in exchange for certain of Company C’s assets and cash. On August 3, 2016, MEP management provided an in person management presentation and responded to additional diligence requests from Company C. The Company C offer was rejected because the cash received would be insufficient to remedy MEP’s financial condition and because of the quality of Company C’s assets proposed to be swapped. Also, as noted above, Enbridge and EEP management determined that piecemeal sales of single assets were unlikely to fix the problems associated with MEP’s financial condition.

On July 1, 2016, EEP received a non-binding proposal from Company D. Company D proposed to acquire, subject to due diligence and other terms and conditions set forth in the proposal, the EEP Interests and assume

 

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MEP’s outstanding debt. The Company D offer was pursued by EEP, and Company D was invited to participate in a second round of the Sale Process. On July 26, 2016, MEP management provided an in person management presentation and responded to additional diligence requests from Company D. However, after progressing to the second round, Company D became less engaged in the contemplated transaction and let its offer lapse despite EEP’s attempts to engage in further discussion.

In mid-September 2016, as the Sale Process described above was reaching its conclusion, management of Enbridge, together with its outside legal counsel, Latham & Watkins LLP (“Latham”), evaluated structuring alternatives for the acquisition by Enbridge or its affiliates of the remaining publicly traded equity securities of MEP that EEP did not already own (the “Buy-In Alternative”). During the remainder of September 2016 and during October 2016, Enbridge, in consultation with Latham and Citi, continued to evaluate the Buy-In Alternative and developed a formal proposal to be delivered to the MEP GP Board and EEM.

On November 28, 2016, representatives of Enbridge management advised the members of the MEP GP Board that management intended to present a potential conflict of interest transaction involving MEP at the December 5, 2016 meeting of the MEP GP Board. The independent board members then began to consider advisors that could represent the independent directors with respect to such a transaction.

On December 1, 2016, Mr. Segner, contacted a representative of Bracewell LLP (“Bracewell”), which had served as counsel to the special committee in prior transactions, including the special committee’s consideration of the MOLP Amendment and the Subscription Agreement, and requested that Bracewell perform a conflicts check. Following that conflicts check, it was determined that Bracewell did not have any conflicts that would preclude it from representing the independent directors in any transaction adverse to Enbridge or EEP.

On December 1, 2016, Mr. Segner also contacted a representative of Evercore, which had served as financial advisor to the special committee in its consideration of the Subscription Agreement, and requested that Evercore perform a conflicts check. Following that conflicts check, it was determined that Evercore did not have any conflicts that would preclude it from representing the independent directors in any transaction adverse to Enbridge or EEP.

On December 2, 2016, the independent board members held a telephonic meeting that included representatives of Bracewell to discuss the retention of legal and financial advisors. After Bracewell left the meeting, the independent board members continued in an executive session and determined to (1) retain Evercore as the independent directors’ independent financial advisor with respect to the MEP Committee’s independent directors’ review and consideration of the transaction to be presented at the December 5, 2016 meeting of the MEP GP Board, subject to the negotiation of a mutually acceptable engagement letter; and (2) retain Bracewell as the independent directors’ independent legal advisor with respect to the independent directors’ review and consideration of the transaction to be presented at the December 5, 2016 meeting of the MEP GP Board.

Following the independent board members meeting on December 2, 2016, Mr. Segner called a representative of Bracewell to inform Bracewell that the independent board members had determined that Bracewell would be the independent legal advisor for the MEP Committee if constituted following the MEP GP Board meeting proposed to be held on December 5, 2016. Mr. Segner also asked that representatives from Bracewell attend the December 5, 2016 MEP GP Board meeting.

On December 5, 2016, Enbridge delivered to the MEP GP Board a proposal letter (the “December 5 Proposal”) that contemplated that EECI would acquire all of the outstanding Class A Common Units not already owned by EEP at a price of $6.25 per unit, the closing price of the Class A Common Units on December 2, 2016, the last trading day prior to December 5, 2016. Enbridge stated that it believed its proposal should be attractive to the MEP Unaffiliated Unitholders, particularly in light of the prolonged deterioration in commodity prices. Enbridge believed that the current trading prices of the Class A Common Units were not indicative of the value of the underlying distressed business of MEP, and that the trading price of the Class A Common Units would

 

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decline precipitously in the event of a reduction in or elimination of the MEP quarterly distribution or a dilutive equity issuance to EEP. The December 5 Proposal stated that the transaction would be structured as a merger between MEP and a wholly owned subsidiary of EECI. In the December 5 Proposal, Enbridge informed the MEP GP Board that Enbridge was interested only in acquiring common units of MEP and not in selling, or causing EEP to sell, interests in MEP or MEP GP or approving any combination of MEP with, or a sale of all or substantially all of the assets of MEP to, any other acquirer.

Also on December 5, 2016, Enbridge delivered to the EEM Board a letter (the “EEP Letter”) describing the matters addressed in the December 5 Proposal. The EEP Letter stated that Enbridge believed the transaction would be beneficial to EEP because, among other things, it would (1) result in the elimination of existing public company costs associated with MEP and (2) provide EEP and Enbridge with increased flexibility with respect to potential future transactions to address the deteriorating gathering and processing business.

Also on December 5, 2016, at a telephonic meeting of the MEP GP Board at which representatives of Evercore and Bracewell were present, members of Enbridge’s management team gave a presentation to the MEP GP Board regarding the December 5 Proposal. During the meeting, Enbridge management discussed with the members of the MEP GP Board: (1) an overview of the December 5 Proposal; (2) management’s views of the current challenges facing MEP and its ability to sustain its current quarterly cash distributions payable on the Class A Common Units; (3) management’s rationale for considering the Merger, including the potential benefits of the Merger to the MEP Unaffiliated Unitholders; and (4) other alternatives to the Merger that had been considered by management, including the Sale Process, EEP providing additional support to MEP pursuant to the Subscription Agreement and significantly reducing or eliminating the quarterly cash distributions payable on the Class A Common Units. During the course of the meeting, the independent board members and representatives of Evercore and Bracewell asked questions regarding the Merger that were responded to by members of Enbridge management.

After discussion and consideration, the MEP GP Board unanimously determined, in the good faith exercise of its reasonable business judgment, that it was advisable and in the best interest of MEP and the MEP Unaffiliated Unitholders to appoint John A. Crum, James G. Ivey and Mr. Segner as the members of the MEP Committee, with Mr. Segner to serve as Chairman, and to empower the MEP Committee to (1) review, evaluate, consider and negotiate the December 5 Proposal on behalf of MEP and the MEP Unaffiliated Unitholders for the purpose of providing, if appropriate, Special Approval (pursuant to the MEP Partnership Agreement) and (2) determine whether or not to give Special Approval of the Merger, the Merger Agreement and the transactions contemplated thereby. In addition, the MEP GP Board unanimously determined that (1) none of Messrs. Crum, Ivey or Segner (nor any of their family members or affiliates) had any material financial or other interest in, or any material relationship with, MEP or Enbridge and its affiliates, nor were they otherwise involved (other than as board members of the MEP GP Board) in the Merger, and (2) each of Messrs. Crum, Ivey and Segner satisfied the independence and other requirements to serve as members of the MEP Committee. After making these determinations, the MEP GP Board adopted resolutions authorizing the MEP Committee to, among other things, (1) review, evaluate, consider and negotiate the terms of the Merger and the Merger Agreement (including the amount and form of the merger consideration), (2) consider alternatives to the Merger, if any, (3) approve or disapprove, as the case may be, MEP entering into the Merger Agreement and the agreements and arrangements related thereto and the transactions contemplated thereby (including the issuance of new Class A Common Units in connection with the Merger), (4) make all determinations and take all actions with respect to the Merger and the Merger Agreement and the agreements and arrangements related thereto and the transactions contemplated thereby as may be authorized and contemplated under the Merger Agreement, the MEP Partnership Agreement and MEP GP’s Amended and Restated Limited Liability Company Agreement, dated as of November 6, 2013, and (5) make a recommendation to the MEP GP Board whether to approve the Merger and the Merger Agreement and the agreements and arrangements related thereto and the transactions contemplated thereby. The MEP GP Board also determined that Mr. Segner would be entitled to $5,000 for his service as Chairman of the MEP Committee and that each member of the MEP Committee would be entitled to a fee of $1,500 per meeting. The MEP GP Board also authorized the MEP Committee to select and retain its own independent legal and

 

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financial advisors. Mr. Segner reported to the MEP GP Board that the MEP Committee had engaged Bracewell as its independent legal advisor and expected to engage Evercore as its independent financial advisor.

Following the MEP GP Board meeting on December 5, 2016, the MEP Committee met with representatives of Evercore and Bracewell and discussed their initial thoughts regarding the December 5 Proposal and next steps to be undertaken, including: (1) the financial analysis to be conducted by Evercore; (2) factors to consider in determining whether the Merger should be conditioned upon a separate vote of the MEP Unaffiliated Unitholders; and (3) reactions to alternative transactions to the Merger considered by Enbridge management, as well as to the projected reduction to the distributions payable on the Class A Common Units, including a discussion of the impact of distribution cuts on trading prices of common units of other publicly traded MLPs. The MEP Committee then discussed the potential terms of Evercore’s engagement with representatives of Bracewell and Evercore, and Evercore committed to provide a draft engagement letter with a fee quotation. The MEP Committee directed Bracewell to complete the negotiation of a mutually acceptable engagement letter with Evercore. The MEP Committee subsequently formally engaged Evercore as the MEP Committee’s independent financial advisor with respect to the MEP Committee’s review and consideration of the Merger.

During the course of the MEP Committee’s review of the Merger, the MEP Committee discussed with Evercore the potential implications to MEP and the MEP Unaffiliated Unitholders of remaining with the status quo rather than approving the Merger; however, Evercore was not authorized to solicit, and did not solicit, interest from any third party with respect to the acquisition of any or all of the Class A Common Units or any business combination or other extraordinary transaction involving MEP.

On December 5, 2016, Evercore received MEP’s budget and long range plan as reviewed by the MEP GP Board and representatives of Evercore submitted a proposed due diligence questions list to Enbridge management.

On December 6, 2016, Evercore met with members of Enbridge management and representatives of Citi to discuss the MEP financial projections. Members of management of MEP had delivered to representatives of Evercore a model prepared by management of MEP detailing MEP’s 2017 budget and the financial projections for MEP, including MOLP (the “Management Projections”).

On December 13, 2016, Evercore met with members of Enbridge management and representatives of Citi via teleconference to discuss the due diligence questions posed by Evercore regarding the Sale Process.

On December 15, 2016, Evercore met with members of Enbridge management and representatives of Citi to discuss the MEP assets and financial projections.

On December 19, 2016, Latham delivered an initial draft of the Merger Agreement to Bracewell that provided for all cash consideration. The initial draft of the Merger Agreement was consistent with the December 5 Proposal. The initial draft of the Merger Agreement provided, among other things, that (1) MEP could not solicit any proposal that could constitute an acquisition proposal (a “no-shop” provision); (2) the MEP Board could only change its recommendation of the Merger if it determined in good faith (after consultation with its financial advisor and outside legal counsel) that an acquisition proposal constitutes a superior proposal and that the failure to take such action would be a material breach of its duties under the MEP Partnership Agreement; and (3) a change in recommendation would not terminate the Merger Agreement or preclude EEP from voting in favor of the Merger. The initial draft of the Merger Agreement also included EEP as a party to the Merger Agreement and contemplated delivery of the Support Agreement.

During the afternoon of December 20, 2016, at a telephonic meeting of the MEP Committee at which representatives of Bracewell and Evercore were present, representatives of Evercore discussed with the MEP Committee the due diligence that had been conducted to date and Evercore’s preliminary financial analysis of the Merger, based on the Management Projections and the proposed merger consideration of $6.25 per Class A Common Unit. During the presentation Evercore provided, among other things: (1) a summary of the terms of the

 

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Merger; (2) a situation analysis for MEP; (3) a detailed overview of MEP’s assets and operations, including MOLP; (4) a summary of the Management Projections, including the underlying assumptions; (5) a detailed preliminary financial analysis of MEP, including a discounted cash flow analysis, a discounted distribution analysis based on various assumed distribution levels and using the reduced future distributions payable on the Class A Common Units under the Management Projections, a precedent M&A transaction analysis, a peer group trading analysis and a premiums paid analysis. Representatives of Evercore then described for the benefit of the MEP Committee the results of Evercore’s diligence regarding the Sale Process and an overview of the summaries of the Sale Process that were prepared by Enbridge. Evercore noted that the Sale Process was unsuccessful and had not, from EEP’s perspective, resulted in any acceptable offers that would allow for MEP’s long-term financial stability. During the presentation, the MEP Committee asked, and representatives of Evercore answered, questions with respect to Evercore’s preliminary financial analysis. Following the presentation, the MEP Committee and its advisors discussed the appropriate response to the December 5 Proposal and the MEP Committee determined to have a representative of Evercore communicate to Enbridge management a counteroffer (the “December 21 Counteroffer”) of consideration for the Class A Common Units that reflects a 15% premium to the 30 trading day VWAP of the Class A Common Units as of the execution date of the Merger Agreement and that such consideration would be payable, at the election of the MEP Unaffiliated Unitholders, in cash or common stock or units of Enbridge or EEP, respectively.

On December 21, 2016, a representative of Evercore called Colin Gruending, Vice President Corporate Development of Enbridge, and presented the terms of the December 21 Counteroffer. As of December 21, 2016, the 30 trading day VWAP of the Class A Common Units was approximately $6.70, a 7.2% increase as compared to Enbridge’s original offer of $6.25 per unit. Evercore also stated that the MEP Committee proposed that the consideration for Class A Common Units be payable in cash or in Enbridge stock or EEP common units, at the election of MEP unitholders. Evercore also asked that Enbridge confirm that MEP would pay the quarterly distribution with respect to the fourth quarter of 2016.

On January 6, 2017, Bracewell asked Enbridge to provide documents related to the Sale Process, including the confidential information memorandum presented to potential buyers that had been previously provided to Evercore, the instructions for providing a bid, any indications of interest provided by potential buyers in the Sale Process and any related documents, any responses by Enbridge, EEP or MEP to such indications of interest and any summary of the Sale Process or the indications of interest received prepared by EEP or its advisors.

On January 6, 2017 and January 9, 2017, Enbridge provided materials responsive to Bracewell’s request for documentation regarding the Sale Process. The materials provided by Enbridge were reviewed by Bracewell and Evercore and discussed with the MEP Committee at subsequent meetings.

On January 8, 2017, Mr. Gruending delivered a letter to the MEP Committee in response to the December 21 Counteroffer (the “January 8 Proposal”). The January 8 Proposal stated that (1) Enbridge would agree to base the merger consideration off of a VWAP of the Class A Common Units as of the execution date of the Merger Agreement and that it believed that 30 days was reasonable, but did not believe that any premium was warranted, (2) Enbridge had considered the MEP Committee’s proposal that the merger consideration be paid in cash or in common stock or units of either Enbridge or EEP, respectively, at the election of the MEP Unaffiliated Unitholders, and that management of Enbridge had declined the MEP Committee’s proposal because, at the time, neither Enbridge nor EEP were willing to issue equity in connection with the Merger, and (3) Enbridge agreed that a regular distribution with respect to the quarter ended December 31, 2016 should be paid by MEP to the holders of the Class A Common Units on the record date. As of January 8, 2017, the 30 trading day VWAP price would have resulted in the MEP’s Unaffiliated Unitholders receiving approximately $6.70 per Class A Common Unit.

On January 9, 2017, at a telephonic meeting of the MEP Committee at which representatives of Evercore and Bracewell were present, a representative of Evercore discussed his recent conversations with Mr. Gruending regarding the January 8 Proposal. The Evercore representative noted that Enbridge would not consider including

 

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common stock or units of Enbridge or EEP, respectively, as a portion of the merger consideration. Representatives of Evercore also discussed with the MEP Committee certain due diligence updates, and responded to questions from the MEP Committee during the course of the discussion. Evercore presented the supplemental financial analysis that it had delivered to the MEP Committee members and Bracewell prior to the meeting, which Evercore explained was a summary of how various potential amounts of merger consideration compared to various metrics of the Class A Common Units’ trading price, including the 10 trading day, 20 trading day and 30 trading day VWAPs for the Class A Common Units. Following the Evercore presentation and related discussions at the meeting, the MEP Committee determined to have Evercore propose to Enbridge management that the merger consideration be the greater of (1) a 20% premium to the 30 trading day VWAP for the Class A Common Units or (2) the current market price of the Class A Common Units, in each case, as of the close of the trading day prior to the execution of the Merger Agreement.

On January 10, 2017, a representative of Evercore had a telephonic conversation with Mr. Gruending in which he communicated a counteroffer of consideration for the Class A Common Units equal to the greater of (1) a 20% premium to the 30 trading day VWAP for the Class A Common Units and (2) the current market price of MEP’s Class A Common Units, in each case, as of the close of the trading day prior to execution of the Merger Agreement, and an agreement that the merger consideration consist only of cash and not of common stock or units of Enbridge or EEP, respectively (the “January 9 Counteroffer”).

On January 11, 2017, Bracewell and Latham held a telephonic meeting to discuss the draft Merger Agreement that Latham provided Bracewell on December 19, 2016. Among the items discussed by Bracewell and Latham were the timing of the transaction, the proposed merger mechanics and treatment of Units owned by EEP and whether filings under the Hart Scott Rodino Act would be required. Bracewell and Latham also discussed whether it would be possible for Enbridge or EEP to issue equity securities as an election for the merger consideration and Latham advised Bracewell that Enbridge and EEP were not willing to agree to issue equity securities. Bracewell and Latham also discussed whether Enbridge would be willing to include a condition in the Merger Agreement that the Merger be approved by the affirmative vote of the MEP Unaffiliated Unitholders holding a majority of the Class A Common Units as a condition to MEP’s obligation to consummate the Merger and Latham advised Bracewell that Enbridge was not willing to agree to such a provision. Bracewell and Latham discussed generally the proposed operational representations of MEP included in the draft Merger Agreement and how the MEP Committee could reasonably diligence such representations. Bracewell and Latham also discussed whether the Management Projections that reflect MEP significantly reducing or eliminating the quarterly cash distributions payable on the Class A Common Units were consistent with the MOLP Amendment. Latham advised Bracewell that it was Enbridge’s view that the MOLP Amendment does not require MEP to pay a quarterly cash distribution and therefore the Management Projections are consistent with the MOLP Amendment.

Also on January 11, 2017, Mr. Gruending had a telephonic conversation with a representative of Evercore in which he communicated Enbridge’s response to the January 9 Counteroffer. Mr. Gruending advised Evercore that he believed that Enbridge may be willing to offer consideration per Class A Common Unit based on the then-current trading price of the Class A Common Units (the “January 11 Proposal”). The closing price of the Class A Common Units on January 11, 2017 was $7.70.

Also on January 11, 2017, the MEP Committee met telephonically with representatives from Bracewell and Evercore for Evercore to present Enbridge’s response to the January 9 Counteroffer. Evercore explained that Mr. Gruending had advised Evercore that Enbridge may be willing to offer consideration of $7.70 per Class A Common Unit, the then-current trading price of the Class A Common Units. The MEP Committee considered the January 11 Proposal and determined to propose consideration per Class A Common Unit equal to the greater of (1) $7.70, the closing price of the Class A Common Units on January 11, 2017, and (2) the trading price of the Class A Common Units as of the execution of the Merger Agreement (the “January 11 Counteroffer”). Following the Evercore presentation and related discussions at the meeting, Mr. Segner asked Bracewell to report on the draft Merger Agreement. Representatives of Bracewell then proceeded to (1) provide the MEP Committee with an overview of the terms of the initial draft of the Merger Agreement and (2) discuss with the MEP Committee a

 

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number of potential negotiation points and recommended changes to the Merger Agreement, including: (A) deleting or modifying the no-shop provision; (B) expanding the circumstances under which the MEP GP Board and/or the MEP Committee could effect a change in its recommendation and making the consequences of any such change more favorable to the MEP Unaffiliated Unitholders, in light of EEP’s expected ownership of a majority of the Class A Common Units at the time the Merger is submitted to a vote of the limited partners of MEP; (C) deleting the operational representations related to MEP, including representations by MEP concerning SEC filings, no undisclosed liabilities, absence of changes, tax matters, environmental matters, regulatory matters, employee benefit matters, title to properties and rights of way; (D) modifying the definition of “material adverse effect”; (E) confirming that MEP would pay a quarterly cash distribution on the Class A Common Units with respect to the quarter ended December 31, 2016, which was contemplated by the January 8 Proposal, and requiring that MEP would pay a quarterly cash distribution on the Class A Common Units with respect to the first quarter of 2017 if the closing had not occurred prior to MEP’s customary record date; and (F) requiring the approval of a majority of the Class A Common Units held by the MEP Unaffiliated Unitholders as a condition to MEP’s obligation to consummate the Merger.

During the course of the meeting, the MEP Committee asked, and representatives of Bracewell answered, various questions with respect to the draft of the Merger Agreement. The MEP Committee and its advisors also discussed factors to consider in connection with determining whether the Merger should be conditioned upon approval by a majority of the Class A Common Units held by the MEP Unaffiliated Unitholders. Following additional discussion, the MEP Committee directed Bracewell to provide a revised draft of the Merger Agreement to Latham reflecting the revisions discussed with the MEP Committee and instructed Evercore to propose the January 11 Counteroffer to Enbridge.

On January 12, 2017, Evercore communicated the January 11 Counteroffer to Enbridge. On January 12, 2017, the closing price of the Class A Common Units was $7.60.

On January 12, 2017, Bracewell provided a revised draft of the Merger Agreement to Latham reflecting the revisions discussed with the MEP Committee, including, among others, (1) the deletion of the no-shop provision, (2) providing for less restrictive circumstances under which the MEP GP Board and/or the MEP Committee could change their recommendations regarding the Merger and providing that any such change of recommendation would act to invalidate and rescind any Special Approval from the MEP Committee of the Merger, (3) deleting the operational representations related to MEP, (4) confirming that MEP would pay a quarterly cash distribution on the Class A Common Units with respect to the quarter ended December 31, 2016, and proposing that MEP pay distributions until the earlier of the Effective Time of the Merger or until the Merger Agreement was terminated and (5) requiring the approval of a majority of the Class A Common Units held by the MEP Unaffiliated Unitholders as a condition to MEP’s obligation to consummate the Merger.

On January 13, 2017, Bracewell and Latham held a telephonic meeting at which the parties discussed the draft of the Merger Agreement that Bracewell provided Latham on January 12, 2017 reflecting the comments of the MEP Committee. Bracewell explained the MEP Committee’s rationale behind the changes that were reflected in the draft Merger Agreement and answered questions asked by Latham.

On January 14, 2017, Latham provided an initial draft of the Support Agreement to Bracewell.

On January 16, 2017, Latham provided a revised draft of the Merger Agreement to Bracewell. The draft accepted the MEP Committee’s proposed deletion of the operational representations and included an agreement that MEP would pay a quarterly cash distribution on the Class A Common Units with respect to the quarter ended December 31, 2016, but did not include an agreement to pay a quarterly distribution with respect to the first quarter of 2017 if the closing did not occur prior to MEP’s customary record date. The draft also rejected (1) the MEP Committee’s proposed deletion of the no-shop provision, (2) the modifications to the circumstances under which the MEP GP Board and/or the MEP Committee could change their recommendations and the consequences of such a change and (3) the inclusion of a provision that would require the approval of a majority

 

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of the Class A Common Units held by the MEP Unaffiliated Unitholders as a condition to MEP’s obligation to consummate the Merger.

On January 17, 2017, Bracewell and Latham held a telephonic meeting during which the parties discussed the draft Merger Agreement that Latham provided to Bracewell on January 16, 2017. Bracewell and Latham discussed the current status of discussions between the parties to the Merger. At the request of Bracewell, Latham reviewed their markup of the Merger Agreement and Enbridge’s rationale for the changes made in the draft of the Merger Agreement. Such comments, among other items, focused on the representations and warranties made by the parties in the Merger Agreement, the flexibility of the MEP GP Board to consider other transactions, certain legal issues, matters raised by precedent transaction documents and outstanding matters that require further diligence by the MEP Committee.

On January 17, 2017, the MEP GP Board held a dinner at which all of the directors of the MEP GP Board were present except for J. Herbert England and Mark A. Maki. During the dinner, members of the MEP Committee indicated to the other directors in attendance, specifically, C. Gregory Harper and R. Poe Reed, that during the MEP GP Board meeting scheduled for the following morning, the MEP Committee desired to receive further information regarding the Sale Process and the initial, non-binding indications of interest received by EEP.

On January 18, 2017, the MEP GP Board (including the members of the MEP Committee) held a meeting to discuss, among other things, the status of the proposed transaction. Representatives of Bracewell and Evercore attended the meeting as did management of Enbridge and EEP. Bracewell provided the MEP GP Board with a detailed summary of the principal proposed terms of the Merger Agreement and Evercore discussed the financial review process and the process, timing and material financial terms of purchase price negotiations held to date. The MEP GP Board, Bracewell and Evercore then held an in-depth discussion with the management of Enbridge and EEP concerning the Sale Process and the viability and status of the initial, non-binding indications of interest received in the process. Management of Enbridge and EEP advised the MEP GP Board (including the members of the MEP Committee) that none of the indications of interest were expected to result in a transaction that would be superior to the Merger and that the assets and business of MEP were not considered a major source of synergies in the acquisition modeling for Enbridge’s pending merger with Spectra Energy Corp or in Enbridge’s public filings relating to such merger. Management of MEP then discussed the Management Projections, which included the elimination of distributions payable on the Class A Common Units in 2017.

On January 18, 2017, representatives of Bracewell and Latham held a telephonic meeting at which the parties discussed Bracewell’s comments to the Merger Agreement concerning the no-shop provision and the circumstances under which the MEP GP Board could change its recommendation of the Merger and the consequences of such a change.

On January 21, 2017, Bracewell provided a revised draft of the Merger Agreement and the Support Agreement to Latham. The January 21, 2017 draft provided by Bracewell to Latham included a no-shop provision but allowed the MEP GP Board to withdraw or change its recommendation regarding the Merger Agreement if it determines in good faith (after consultation with its financial advisors, outside legal counsel and the MEP Committee) that an acquisition proposal is a superior proposal and that the failure to take such action would be materially adverse to the interests of the MEP Unaffiliated Unitholders or would otherwise be a breach of the its duties under the MEP Partnership Agreement or applicable law, subject to a customary notice and negotiation period in favor of EECI. In addition, if the MEP GP Board were to change its recommendation, each of MEP and EECI would then have the option to terminate the Merger Agreement and, under the terms of the Support Agreement, the Support Agreement would automatically terminate.

On January 23, 2017, Bracewell and Latham held a telephonic meeting at which the parties discussed the draft of the Merger Agreement that Bracewell provided Latham on January 21, 2017 reflecting the comments of the MEP Committee.

 

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On January 23, 2017, Latham provided revised drafts of the Merger Agreement and Support Agreement to Bracewell. The January 23, 2017 drafts generally accepted the changes proposed by the MEP Committee in its January 21, 2017 drafts.

During the afternoon of January 24, 2017, at a telephonic meeting of the MEP Committee at which representatives of Evercore and Bracewell were present, representatives of Evercore updated the MEP Committee regarding: (1) additional sensitivity analyses performed by Evercore concerning the distribution cut reflected in the Management Projections and the impact such a reduction in distributions would have on the market price for the Class A Common Units (“Sensitivity Analyses”); (2) the resulting implications to Evercore’s preliminary financial analysis, including updated assumptions used by Evercore; and (3) updates to Evercore’s presentation materials. The MEP Committee and its advisors then engaged in a discussion regarding: (1) the potential benefits to the MEP Unaffiliated Unitholders of the Merger; (2) the potential implications to MEP and the MEP Unaffiliated Unitholders if the MEP Committee and management of Enbridge were not able to reach agreement on a mutually acceptable merger consideration and the MEP Committee were to decline to approve the Merger in favor of remaining with the status quo; and (3) the next steps involved in evaluating the Merger and negotiating the merger consideration. The MEP Committee then discussed whether it would be appropriate for the MEP GP Board to declare a distribution on the Class A Common Units in respect of the fourth quarter of 2016 in light of the Management Projections if no agreement is reached with Enbridge with respect to the Merger. It was the consensus of the MEP Committee that the MEP GP Board should consider and discuss such matters if no agreement was reached with Enbridge with respect to the Merger.

During the period beginning on December 5, 2016, the date that Enbridge made its initial proposal of $6.25 per Class A Common Unit and continuing through January 24, 2017, there was a large and unexpected increase in the market price of the Class A Common Units. The market price of the Class A Common Units increased by 31.3% during this period from a closing price of $6.55 on December 5, 2016 to a closing price of $8.60 on January 24, 2017, compared to an increase of 8.4% in the price of a basket of securities of peer group MLPs. During this time, there were no changes in MEP’s underlying business or financial condition to support such an increase in the market price of the Class A Common Units.

On January 24, 2017, following the meeting of the MEP Committee, Mr. Gruending had a telephonic conversation with a representative of Evercore in which he discussed the recent unexpected increase in the trading price of MEP common units and Enbridge’s determination that offering cash consideration equivalent to the trading price of the Class A Common Units was no longer appropriate. Mr. Gruending communicated that Enbridge would offer $7.50 per Class A Common Unit (the “January 24 Proposal”).

During the evening of January 24, 2017, at a telephonic meeting of the MEP Committee at which representatives of Evercore and Bracewell were present, representatives of Evercore updated the members of the MEP Committee that Enbridge had offered a purchase price for the Class A Common Units of $7.50 per Class A Common Unit in the January 24 Proposal. The MEP Committee then engaged in a discussion of how the January 24 Proposal compared to the various metrics on which it had evaluated the transaction, including Evercore’s financial analysis, and determined unanimously to reassert the January 11 Counteroffer. The MEP Committee further discussed whether it was appropriate for the MEP GP Board to declare a distribution on the Class A Common Units in respect of the fourth quarter of 2016.

During the evening of January 24, 2017, Bracewell provided revised drafts of the Merger Agreement and Support Agreement to Latham.

Following the telephonic meeting, a representative of Evercore informed Enbridge that the MEP Committee had determined to reiterate the January 11 Counteroffer that the consideration per Class A Common Unit be the greater of (1) $7.70 or (2) the closing price of the Class A Common Units on the date prior to the date of execution of the Merger Agreement.

 

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On January 25, 2017, Mr. Gruending contacted representatives of Evercore to request that he and Vern Yu, Executive Vice President and Chief Development Officer of Enbridge, be permitted to talk directly to the MEP Committee concerning the January 24 Proposal and the MEP Committee’s proposed counteroffer.

During the morning of January 25, 2017, the MEP Committee held a telephonic meeting at which representatives of Evercore and Bracewell and Messrs. Gruending and Yu were present. Messrs. Gruending and Yu entered into a discussion of how Enbridge viewed the rise in the trading price of the Class A Common Units as anomalous when compared to its peer group of gas gathering and processing MLPs and the underlying financial performance of MEP. Messrs. Gruending and Yu conveyed that Enbridge believed that the January 24 Proposal was beneficial to the MEP Unaffiliated Unitholders as the proposed consideration of $7.50 per Class A Common Unit represented an attractive premium to the intrinsic valuation of MEP, represented a premium to various trading day VWAPs for the Class A Common Units and was 20% higher than Enbridge’s initial offer. Messrs. Gruending and Yu also expressed that Enbridge remained committed to the proposed transaction, but that the price in the January 24 Proposal was approaching the limit at which Enbridge would no longer support the transaction. In response to the MEP Committee’s proposed counteroffer, Messrs. Gruending and Yu then presented the MEP Committee with the choice of two alternatives to determine the consideration for the Class A Common Units: (1) $7.80 per Class A Common Unit or (2) the 20 trading day VWAP of the Class A Common Units with a collar between $7.70 and $7.90 per Class A Common Unit (the “January 25 Response”). Messrs. Gruending and Yu explained that Enbridge’s offer would expire at 5:00 p.m. on January 25, 2017. Messrs. Gruending and Yu reminded the MEP Committee that, absent reaching an agreement on the contemplated Merger, (1) Enbridge believed MEP’s financial condition and outlook would further diminish, (2) that it would be likely that MEP would require a reduction or elimination in MEP’s quarterly distributions and/or a dilutive issuance of MEP units to address MEP’s debt covenant compliance issues and (3) that MEP would likely publicly announce the details of items (1) and (2) in connection with the announcement of MEP’s distribution for the fourth quarter of 2016. In response to a question from Bracewell, the representatives of management of Enbridge indicated that Enbridge would not be willing to proceed with the Merger if the approval of the MEP Unaffiliated Unitholders were included as a condition to closing.

Messrs. Gruending and Yu then left the meeting and the MEP Committee discussed the January 25 Response with its legal and financial advisors. After a prolonged discussion, including consideration of whether MEP could continue with the status quo in light of the Management Projections, the MEP Committee determined to propose that the consideration be $8.00 per Class A Common Unit.

Following the meeting of the MEP Committee on January 25, 2017, a representative of Evercore informed Mr. Gruending that the MEP Committee was prepared to approve the Merger with consideration of $8.00 per Class A Common Unit.

During the afternoon of January 25, 2017, Mr. Gruending called Evercore and informed Evercore that Enbridge accepted the offer of $8.00 per Class A Common Unit. The $8.00 per Class A Common Unit merger consideration represented a premium of (i) approximately 28% to the $6.25 price offered by Enbridge in the December 5 Proposal and (ii) approximately 5.5% to the 30 trading day VWAP of the Class A Common Units as of January 26, 2017, the last trading day prior to the public announcement the Merger Agreement.

During the evening of January 25, 2017, Latham provided revised drafts of the Merger Agreement and Support Agreement to Bracewell.

On the morning of January 26, 2017, at a meeting of the MEP Committee at which representatives of Evercore and Bracewell were present, Evercore presented its financial analysis of the Merger Consideration of $8.00 per Class A Common Unit, noting that its materials and financial analyses were substantially equivalent to those most recently presented to the MEP Committee and had been updated to reflect the Merger Consideration. After the MEP Committee discussed Evercore’s presentation, representatives from Evercore then confirmed that Evercore was prepared to deliver a fairness opinion to the MEP Committee based on the Merger Consideration of

 

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$8.00 per Class A Common Unit if so requested by the MEP Committee. Representatives of Bracewell then provided an overview of the terms of the final draft of the Merger Agreement, explained the final negotiated changes to the Merger Agreement and the Support Agreement, and answered questions from the MEP Committee regarding the terms of the agreements. At the request of the MEP Committee, Evercore then delivered its oral opinion, which was later confirmed by delivery of a written opinion dated January 26, 2017, that, as of January 26, 2017 and based upon and subject to the factors, procedures, limitations and other matters set forth in its written opinion, the Merger Consideration was fair, from a financial point of view, to the MEP Unaffiliated Unitholders. After further discussions and based on prior conclusions of the MEP Committee with respect to the risks and merits of the Merger, the MEP Committee unanimously: (1) determined that the Merger Agreement, the Support Agreement and the Merger Transactions were fair and reasonable to and in the best interests of MEP, MEP’s subsidiaries and the MEP Unaffiliated Unitholders; (2) approved the Merger Agreement, the Support Agreement and the Merger Transactions (such approval constituting “Special Approval” as defined in the MEP Partnership Agreement); (3) recommended that the MEP GP Board approve the Merger Agreement and the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement by MEP and the consummation of the Merger Transactions; and (4) recommended that the MEP GP Board submit the Merger Agreement to a vote of the limited partners of MEP and recommend the approval of the Merger Agreement, including the Merger, by the limited partners of MEP.

In the afternoon of January 26, 2017, at a special meeting of the MEP GP Board at which all members of the MEP GP Board as well as management of Enbridge and representatives of Bracewell were present, the MEP GP Board received the report of Mr. Segner, in his capacity as Chairman of the MEP Committee. Mr. Segner reported that the MEP Committee had reviewed the Merger Consideration, the Merger Agreement and the Support Agreement and, based on the foregoing, the MEP Committee delivered its Special Approval (under the MEP Partnership Agreement) of the Merger. In addition, Mr. Segner confirmed that the MEP Committee had received an oral opinion from Evercore as to the fairness, from a financial point of view, of the Merger Consideration to the MEP Unaffiliated Unitholders.

On January 26, 2017, at a meeting of the EEM Board, acting in part based on the recommendation of the EEM Conflicts Committee, the EEM Board determined that the Merger Agreement and the Merger Transactions, were fair and reasonable to, and in the best interests of, EEP, including its partners, and authorized and approved the voting or consent by EEP, (1) as the sole member of MEP GP and (2) of the MEP common units owned by EEP, in favor of the Merger Transactions, including the adoption and approval of the Merger Agreement and the Support Agreement, and (3) authorized and approved EEP’s entry into the Support Agreement.

On January 26, 2017, at a meeting of the board of directors of EECI (“EECI Board”), the EECI Board (1) determined that the Merger was in the best interests of EECI and EEP, and declared it advisable to enter into the Merger Agreement and the Support Agreement and (2) approved the adoption of the Merger Agreement, the Support Agreement, the execution, delivery and performance of the Merger Agreement and the consummation of the Merger Transactions.

Later in the afternoon of January 26, 2017, at a re-convened meeting of the MEP GP Board, Mr. Maki then provided an overview of the Merger and the necessary steps required under the Merger Agreement to proceed to closing. After discussion and based in part upon the approval and recommendation of the Merger by the MEP Committee, the MEP GP Board unanimously (1) deemed it advisable and in the best interests of MEP, MEP’s Subsidiaries and MEP’s limited partners that the Merger Agreement and the Merger Transactions be consummated and therefore unanimously approved the Merger Agreement, the Support Agreement and the Merger Transactions; (2) declared it advisable and in the best interests of MEP GP that MEP GP, on its own behalf and on behalf of MEP, execute, deliver and perform the Merger Agreement and the Support Agreement, and consummate the Merger Transactions; and, (3) on behalf of MEP GP, authorized and directed that the Merger Agreement be submitted to a vote of the limited partners of MEP and, as permitted by the MEP Partnership Agreement, authorized the limited partners of MEP to act by written consent without a meeting in connection with consenting to the Merger Agreement and the Merger Transactions, and (4) recommended that the limited partners of MEP vote in favor of the Merger.

 

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In the evening of January 26, 2017, the Merger Agreement and the Support Agreement were executed by the parties.

In the morning of January 27, 2017, Enbridge, EEP and MEP issued news releases announcing the Merger Agreement, and EEP held an analyst call to discuss a number of recent actions, including the Merger Agreement and the Merger Transactions.

Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties

The approval of the Merger Agreement, the Support Agreement and the Merger Transactions by a majority of the members of the MEP Committee acting in good faith constitutes Special Approval. Under Section 7.9(a) of the MEP Partnership Agreement, whenever a potential conflict of interest exists, such as consideration of the Merger Agreement, the Support Agreement and the Merger Transactions, any resolution or course of action by MEP GP or its affiliates in respect of such conflict of interest will be permitted and deemed approved by all of the partners of MEP, and will not constitute a breach of the MEP Partnership Agreement or of any duty under the MEP Partnership Agreement or stated or implied by law, in equity or otherwise, if the resolution or course of action is approved by Special Approval.

Under Section 7.9(b) of the MEP Partnership Agreement, whenever MEP GP or the MEP GP Board, or any committee thereof (including the MEP Committee), makes a determination or takes or declines to take any other action, or any affiliate of MEP GP causes MEP GP to do so, in its capacity as the general partner of MEP as opposed to its individual capacity, then unless another express standard is provided for in the MEP Partnership Agreement, MEP GP, the MEP GP Board or such committee or such affiliates causing MEP GP to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different duties or standards (including fiduciary duties or standards) imposed by the MEP Partnership Agreement, any other agreement contemplated by the MEP Partnership Agreement or under applicable law.

A determination or other action or inaction will conclusively be deemed to be in “good faith” for all purposes of the MEP Partnership Agreement if the person or persons making such determination or taking or declining to take such other action subjectively believe that the determination or other action or inaction is in the best interests of the Partnership Group as defined in the MEP Partnership Agreement. In making such determination or taking or declining to take such other action, such person or persons may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to MEP.

Under Section 7.10(b) of the MEP Partnership Agreement, any action taken or omitted to be taken by, among others, MEP GP or directors of the MEP GP Board in reliance upon the advice or opinion of legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by such person as to matters reasonably believed to be in such adviser’s professional or expert competence, will be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

Recommendation of the MEP Committee and the MEP GP Board; Reasons for Recommending Approval of the Merger Agreement and the Merger Transactions

The MEP Committee

The MEP Committee consists of three independent directors: Mr. Crum, Mr. Ivey and Mr. Segner. The MEP Committee retained Bracewell as its independent legal counsel. In addition, the MEP Committee retained Evercore as its independent financial advisor. The MEP Committee oversaw the performance of financial and legal due diligence by its advisors, conducted an extensive review and evaluation of EECI’s proposal and conducted negotiations with EECI and its representatives with respect to the Merger Agreement, the Support Agreement and the Merger Transactions.

 

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The MEP Committee considered the benefits of the Merger Agreement, including the Merger as well as the associated risks, and on January 26, 2017, unanimously (1) resolved that the Merger Agreement, the Support Agreement and the Merger Transactions are fair and reasonable to and in the best interests of MEP, MEP’s subsidiaries and the MEP Unaffiliated Unitholders, (2) approved the Merger Agreement, the Support Agreement and the Merger Transactions, (3) recommended that the MEP GP Board approve the Merger Agreement, the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement by MEP and the consummation of the Merger Transactions and (4) recommended that the MEP GP Board submit the Merger Agreement to a vote of the limited partners of MEP and recommend the approval of the Merger Agreement, including the Merger, by the limited partners of MEP. For more information regarding the recommendation of the MEP Committee, see “The Merger — Reasons for the MEP Committee’s Recommendation.”

Based in part upon such approval and recommendation, at a meeting duly called and held on January 26, 2017, the MEP GP Board approved the Merger Agreement, the Support Agreement and the Merger Transactions; declared it advisable and in the best interests of MEP GP that MEP GP, on its own behalf and on behalf of MEP, to execute, deliver and perform the Merger Agreement and the Support Agreement, and consummate the Merger and engage in all transactions related thereto, including the Merger; and, on behalf of MEP GP, authorized and directed that the Merger Agreement be submitted to a vote of the limited partners of MEP and, as permitted by the MEP Partnership Agreement, authorized the limited partners of MEP to act by written consent without a meeting in connection with consenting to the Merger Agreement, including the Merger.

Reasons for the MEP Committee’s Recommendation

The MEP Committee consulted with its independent financial and legal advisors and considered many factors in making its determination and approvals, and the related recommendation to the MEP GP Board. The MEP Committee considered the following factors to be generally positive or favorable in making its determination and approvals, and the related recommendation to the MEP GP Board:

 

    The delivery of an opinion by Evercore to the MEP Committee on January 26, 2017, that, as of January 26, 2017 and based upon and subject to the factors, procedures assumptions, qualifications, limitations and other matters set forth therein, the Merger Consideration was fair, from a financial point of view, to the MEP Unaffiliated Unitholders including the various analyses undertaken by Evercore in connection with its opinion which are described under “Opinion of Evercore Group L.L.C. – Financial Advisor to the MEP Committee – Analysis of MEP.”

 

    The Merger would provide the MEP Unaffiliated Unitholders with Merger Consideration of $8.00 per Class A Common Unit, a price the MEP Committee viewed as fair in light of MEP’s recent financial challenges and projected poor financial performance. Such consideration amount represented a premium of approximately 5.5% above the VWAP of a Class A Common Unit for the 30 consecutive NYSE full trading days ending at the close of regular trading hours on the NYSE on January 26, 2017 (the last trading day before the announcement of the Merger Agreement and the Merger Transactions).

 

    The Merger Consideration of $8.00 per Class A Common Unit represents a 28% increase from the value of the Merger Consideration originally offered by Enbridge in the December 5 Proposal.

 

    The MEP GP Board would declare a cash distribution in respect of the fourth quarter of 2016 in the amount of $0.3575 per unit on all of its outstanding common and subordinated units.

 

   

The MEP Committee’s belief that it was unlikely that any other transaction with a third party involving a sale of MEP or significant interest in MEP or its assets could be consummated at the time of the MEP Committee’s determination and approval in light of (1) the results of the Sale Process and (2) Enbridge’s position stated in the December 5 Proposal that it was only interested in acquiring all of the outstanding Class A Common Units owned by the MEP Unaffiliated Unitholders and had no interest in approving any combination of MEP with, or a sale of all or substantially all of the assets of

 

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MEP to, any other acquirer. In addition, the MEP Committee considered the potential implications to MEP and the MEP Unaffiliated Unitholders of remaining with the status quo rather than approving the Merger Agreement and the Merger, taking into account the potential financial impact to the MEP Unaffiliated Unitholders of the projected elimination of quarterly cash distributions on the Class A Common Units as reflected in the Management Projections.

 

    The MEP Committee’s belief that the January 25 Proposal was Enbridge’s final offer and the conclusion reached by the MEP Committee that the $8.00 per Class A Common Unit was likely the highest price per Class A Common Unit that Enbridge would be willing to pay at the time of the MEP Committee’s determination and approval.

 

    The MEP Committee’s belief that the trading price of the Class A Common Units would decline significantly upon MEP’s disclosure of the reduction in distributions payable on the Class A Common Units as reflected in the Management Projections.

 

    The MEP Committee’s belief that, under the status quo, the MEP Unaffiliated Unitholders would experience significant dilution as a result of MEP’s efforts to maintain compliance with the financial covenants in the Loan Documents as detailed by Enbridge on the morning of January 25, 2017.

 

    Certain terms of the Merger Agreement and the Support Agreement, principally:

 

    each Class A Common Unit owned by the MEP Unaffiliated Unitholders will be converted into the right to received cash equal to $8.00;

 

    prior to the Effective Time, each Class A Common Unit would also receive $0.3575 as a cash distribution in respect of the fourth quarter of 2016;

 

    the limited nature of the operational representations and warranties given by MEP;

 

    the consummation of the Merger is not conditioned on financing;

 

    the provision allowing the MEP GP Board to withdraw or change its recommendation if it determines in good faith (after consultation with its financial advisors, outside legal counsel and the MEP Committee) that an acquisition proposal is a superior proposal and that the failure to take such action would be materially adverse to the interests of the MEP Unaffiliated Unitholders or would otherwise be a breach of the its duties under the MEP Partnership Agreement or applicable law, subject to a customary notice and negotiation period in favor of EECI;

 

    the provision allowing MEP to terminate the Merger Agreement upon the MEP GP Board changing its recommendation regarding the Merger;

 

    the lack of a break-up fee for termination of the Merger Agreement in accordance with its terms; and

 

    that under the Support Agreement, EEP has agreed to deliver a written consent adopting and approving in all respects the Merger Agreement and the Merger Transactions unless there is a change in the MEP GP Board’s recommendation in which case the Support Agreement automatically terminates.

In addition, the MEP Committee also considered a number of factors relating to the procedural safeguards involved in the negotiation of the Merger Agreement, including those discussed below, each of which supported its determination with respect to the Merger:

 

    Each of the members of the MEP Committee satisfies the requirements for serving on the MEP Committee as required under the MEP Partnership Agreement, including the requirement that all members of the MEP Committee be independent directors.

 

   

In connection with the consideration of the Merger, the MEP Committee retained its own independent financial and legal advisors with knowledge and experience with respect to public merger and

 

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acquisition transactions, and MEP’s industry specifically, as well as substantial experience advising publicly traded MLPs and other companies with respect to transactions similar to the Merger.

 

    Under the terms of the Merger Agreement, prior to the Effective Time, EECI will not, and will not permit that any of its subsidiaries to, eliminate the MEP Committee, revoke or diminish the authority of the MEP Committee or remove or cause the removal of any director of the MEP GP Board who is a member of the MEP Committee either as a director or as a member of such committee, without the affirmative vote of the members of the MEP GP Board, including the affirmative vote of the other members of the MEP Committee.

 

    The Merger Agreement may not be amended without the approval of the MEP Committee.

 

    Whenever a determination, agreement, decision, approval or consent of MEP or the MEP GP Board is required pursuant to the Merger Agreement, including any decision or determination by MEP to terminate the Merger Agreement or any decision or determination by MEP to withdraw, modify or qualify in a manner adverse to EECI, its recommendation to the limited partners to approve the Merger Agreement or to recommend an acquisition proposal, such determination, decision, approval or consent must be made after consultation with the MEP Committee.

 

    The terms and conditions of the Merger Agreement and the Merger were determined through negotiations between Enbridge and the MEP Committee and their respective representatives and advisors.

The MEP Committee considered the following factors to be generally negative or unfavorable in making its determination and approvals, and the related recommendation to the MEP GP Board:

 

    The Merger Consideration represents a discount based on the closing price of Class A Common Units as of January 26, 2017 (the last trading day prior to the public announcement of the Merger).

 

    The Merger Agreement does not require MEP to pay a cash distribution in respect of any quarter in 2017.

 

    Following the termination of the subordination period on February 15, 2017, EEP owns approximately 52% of the outstanding Class A Common Units, and the Merger Agreement and the Merger are not conditioned on a vote by, and the approval of, a majority of the Class A Common Units held by the MEP Unaffiliated Unitholders, and therefore EEP owns a sufficient number of Class A Common Units to approve the Merger Agreement and the Merger without a vote of the MEP Unaffiliated Unitholders. The MEP Committee determined not to continue to pursue a term requiring the Merger to be approved by such a vote after considering the economic terms of the Merger, Enbridge’s stated position that it would not agree to such a term, the procedural safeguards that had been involved in the negotiation of the Merger and the Merger Agreement, and the other factors discussed in this section.

 

    The MEP Unaffiliated Unitholders will not have equity participation in MEP, or, as a potential portion of the merger consideration, in EEP or Enbridge, following the effective time of the Merger, and the MEP Unaffiliated Unitholders will accordingly cease to participate in MEP’s future earnings or growth, if any, or to benefit from increases, if any, in the value of the Class A Common Units. The MEP Committee determined not to continue to negotiate for merger consideration that consisted of common stock or units of Enbridge or EEP, respectively, after considering the economic terms of the Merger, Enbridge’s stated position that it would not agree to such a term, the procedural safeguards that had been involved in the negotiation of the Merger and the Merger Agreement and the other factors discussed in this section.

 

    The Merger will be a taxable transaction to the MEP Unaffiliated Unitholders for U.S. federal income tax purposes (See “Material U.S. Federal Income Tax Consequences”).

 

    The MEP Unaffiliated Unitholders are not entitled to appraisal rights under the Merger Agreement, the MEP Partnership Agreement or Delaware law.

 

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    Although the MEP Committee believed that the Sale Process was robust, the MEP Committee was not authorized to, and did not, independently conduct an auction process or other solicitation of interest from third parties for the acquisition of MEP or its assets.

 

    The Merger might not be completed in a timely manner, or at all, and a failure to complete the Merger could negatively affect the trading price of Class A Common Units.

 

    Litigation may be commenced in connection with the Merger and such litigation may increase costs and result in a diversion of management focus.

In making its determination and approvals, and the related recommendation to the MEP GP Board, the MEP Committee reviewed (i) the current and historical market prices of the Class A Common Units at numerous dates and multiple VWAPs as of January 25, 2017 and (ii) other related trends with respect to how the Class A Common Units traded historically. While the MEP Committee reviewed the historical prices and other trading trends of the Class A Common Units, it was the belief of the MEP Committee that the historical prices and market trends did not necessarily reflect MEP’s underlying business or financial condition and were not indicative of the deterioration in MEP’s financial condition. In making its determination and approvals, and the related recommendation to the MEP GP Board, the MEP Committee did not consider the liquidation value of the assets of MEP or any of its subsidiaries because it considers MEP to be a viable going concern business where value is derived from cash flows generated from its continuing operations and it believes that the value of MEP’s assets, and the assets of its subsidiaries, that might be realized in a liquidation would be less than MEP’s going concern value. In addition, the MEP Committee did not consider MEP’s net book value, which is defined as total assets minus total liabilities, because the MEP Committee believed that net book value was not a material indicator of the value of MEP as a going concern. While there was no date on which the MEP Committee determined not to consider MEP’s net book value, the net book value of MEP’s partnership interests, excluding noncontrolling interests, was approximately $1.509 billion, or $32.70 per unit, as of September 30, 2016 and approximately $1.471 billion, or $31.87 per unit, as of December 31, 2016 (based on the number of outstanding Class A Common Units, Subordinated Units and general partner units as of such dates). On February 15, 2017, the Subordinated Units were converted into common units on a one-for-one basis after MEP paid its quarterly cash distribution for the quarter ended December 31, 2016. As discussed below, the MEP Committee did not find net book value, an accounting concept, as indicative of MEP’s going concern value. For example, net book value does not take into account the future prospects of MEP, market conditions or trends in MEP’s industry. Except for the proposals made in connection with the Sale Process, the MEP Committee was not aware of, and thus did not consider, any firm offers or proposals made by any unaffiliated person during the past two years for: (1) a merger or consolidation of MEP with another company; (2) the sale or transfer of all or substantially all of MEP’s assets; or (3) the purchase of MEP securities that would enable such person to exercise control of or significant influence over MEP. The MEP Committee is not aware of, and thus did not consider, any purchases by EEP of Class A Common Units during the past two years.

In making its determination and approvals, and the related recommendations, the MEP Committee considered the financial analyses regarding MEP prepared by Evercore and reviewed and discussed by Evercore with the MEP Committee as an indication of the going concern value of MEP. The MEP Committee did not expressly establish a specific going concern value for MEP to determine the fairness of the Merger Consideration to the MEP Unaffiliated Unitholders because the MEP Committee did not believe there was a single method for determining going concern value. However, the financial analyses presented to the MEP Committee by Evercore, which included a discounted cash flow analysis, a selected precedent transactions analysis, a premiums paid analysis and a selected public companies analysis as described under “—Opinion of Evercore Group L.L.C. – Financial Advisor to the MEP Committee,” were based on the operations of MEP as a continuing business and, to that extent, the MEP Committee considered such analyses as going concern valuations. The MEP Committee considered each of these analyses in the context of the fairness opinion provided by Evercore, and the MEP Committee expressly adopted these analyses and the opinion of Evercore, among the other factors it considered (as described above), in reaching its conclusions regarding the fairness of the Merger Agreement and the Merger Transactions to the MEP Unaffiliated Unitholders. A majority of the independent directors of MEP GP, acting

 

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separately from the MEP Committee, did not otherwise vote to retain an unaffiliated representative to act solely on behalf of the MEP Unaffiliated Unitholders for purposes of negotiating the terms of the Merger Agreement or delivering a fairness opinion.

The foregoing discussion of the information and factors considered by the MEP Committee is not intended to be exhaustive, but includes material factors the MEP Committee considered. In view of the variety of factors considered in connection with its evaluation of the Merger and the complexity of these matters, the MEP Committee did not find it useful and did not attempt to quantify or assign any relative or specific weights to the various factors considered in making its determination and recommendation. In addition, each of the members of the MEP Committee may have given differing weights to different factors. Overall, the MEP Committee believed that the positive factors supporting the Merger outweighed the negative factors it considered.

The explanation of the reasoning of the MEP Committee and certain information presented in this section are forward-looking in nature and, therefore, the information should be read in light of the factors discussed in the section entitled “Cautionary Statement Regarding Forward-Looking Statements.”

The MEP GP Board

The MEP GP Board consists of eight directors: (1) five of whom are independent (J. Herbert England, Dan A. Westbrook, John A. Crum, James G. Ivey and Edmund P. Segner III), except that two of such directors serve on one or more boards of directors of Enbridge affiliates, and (2) three of whom are officers of Enbridge or its affiliates, including officers of MEP GP. As such, the directors on the MEP GP Board may have different interests in the Merger than the MEP Common Unitholders. For a complete discussion of these and other interests of the members of the MEP GP Board in the Merger, see “Special Factors—Interests of Certain Persons in the Merger.” Because of such possible and actual conflicts of interest, the MEP GP Board delegated to the MEP Committee the full power and authority of the MEP GP Board to (1) review, evaluate, consider and negotiate the terms and conditions of the proposed transaction; (2) consider alternatives to the proposed transaction, if any; and (3) determine whether or not to recommend for approval to the MEP GP Board the proposed transaction, any such recommendation of such transaction made in good faith to constitute “Special Approval” as such term is defined in the MEP Partnership Agreement.

On January 26, 2017, the MEP Committee unanimously resolved that the Merger Agreement, the Support Agreement and the Merger Transactions are fair and reasonable to and in the best interests of MEP, MEP’s subsidiaries and the MEP Unaffiliated Unitholders. Based upon such determination, the MEP Committee recommended to the MEP GP Board that the MEP GP Board approve the Merger Agreement, the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement by MEP and the consummation Merger Transactions. On January 26, 2017, the MEP GP Board, after considering the factors discussed below, including the unanimous determination and recommendation of the MEP Committee, and after receiving the approval of the MEP GP’s sole member, unanimously determined that each of the Merger Agreement, the Support Agreement and the Merger Transactions is fair and reasonable to and in the best interests of MEP, MEP’s subsidiaries and the MEP Unaffiliated Unitholders and approved the Merger Agreement, the Support Agreement, the execution, delivery and performance of the Merger Agreement and Support Agreement by MEP GP and MEP, the consummation of the Merger Transactions and the submission of the Merger Agreement to a vote of MEP’s limited partners.

In determining that the Merger Agreement and the Merger Transactions are fair and reasonable to, and in the best interest of, MEP and the MEP Unaffiliated Unitholders, and approving the Merger Agreement, the Support Agreement and the Merger Transactions, and recommending that MEP’s limited partners vote in favor of the Merger Agreement and the Merger Transactions, the MEP GP Board considered a number of factors, including the following material factors:

 

    the unanimous approval and recommendation of the MEP Committee; and

 

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    the factors considered by the MEP Committee, including the material factors considered by the MEP Committee described under “—The MEP Committee” above.

In doing so, the MEP GP Board expressly adopted the analysis of the MEP Committee, which is discussed above.

The foregoing discussion of the information and factors considered by the MEP GP Board is not intended to be exhaustive, but includes material factors the MEP GP Board considered. In view of the variety of factors considered in connection with its evaluation of the Merger and the complexity of these matters, the MEP GP Board did not find it useful and did not attempt to quantify or assign any relative or specific weights to the various factors considered in making its determination and recommendation. In addition, each of the members of the MEP GP Board may have given differing weights to different factors. The MEP GP Board approved and recommends that MEP Common Unitholders vote in favor of the Merger Agreement and the Merger Transactions based upon the totality of the information presented to and considered by the MEP GP Board.

The Merger Agreement, the Support Agreement and the Merger Transactions were approved by the MEP GP Board, acting based on the recommendation of the MEP Committee, as described in the section entitled “—Recommendation of the MEP Committee and the MEP GP Board; Reasons for Recommending Approval of the Merger Agreement and the Merger Transactions” of this information statement.

Unaudited Financial Projections of MEP and MOLP

MEP management does not routinely publish projections that are disclosed to the public markets as to long-term future performance, earnings or dividends and distributions. In connection with the proposed Merger, and in the normal course of its long range planning process, management of MEP prepared non-public projections relating to the future financial and operating performance of MEP and MOLP with respect to the period from 2017 to 2020. The Management Projections and Forward Curve Financial Projections summarized below were provided to Evercore for use and consideration in its financial analysis and in preparation of its opinion to the MEP Committee. MEP management did not provide any other financial projections to Evercore. The summary of these projections is included below to give the MEP Unaffiliated Unitholders access to certain non-public unaudited prospective financial information that was made available to Evercore, the MEP Committee and the MEP GP Board in connection with the proposed Merger.

You should be aware that uncertainties are inherent in prospective financial information of any kind. Neither MEP nor any of its affiliates, advisors, officers, directors, or representatives has made or makes any representation or can give any assurance to any MEP Unaffiliated Unitholder, or any other person, regarding the ultimate performance of MEP and MOLP compared to the summarized information set forth below or that any such results will be achieved.

The inclusion of the following summary projections in this information statement should not be regarded as an indication that MEP, or its respective advisors or other representatives, considered or consider the projections to be a reliable or accurate prediction of future performance or events, and the summary projections set forth below should not be relied upon as such.

The MEP and MOLP projections summarized below were prepared by, and are the responsibility of, employees of Enbridge. The MEP and MOLP projections were only prepared for internal planning purposes and not with a view toward public disclosure or toward compliance with GAAP, the published guidelines of the SEC, or the guidelines established by the American Institute of Certified Public Accountants. Neither PricewaterhouseCoopers LLP (“PwC”), nor any other independent registered public accounting firm, has compiled, examined or performed any procedures with respect to the prospective financial information contained in the projections, and accordingly, PwC does not express an opinion or any other form of assurance with respect thereto. PwC has not given advice or consultation in connection with the proposed Merger. The PwC reports incorporated by reference into this information statement with respect to MEP and MOLP relate to historical financial information of MEP and MOLP, respectively. Such reports do not extend to the projections included

 

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below and should not be read to do so. Neither the MEP GP Board, the MEP Committee, nor the MEP GP Board gives any assurance regarding, the summarized information.

The internal financial projections of MEP and MOLP are, in general, prepared primarily for internal use. Such internal financial projections are inherently subjective in nature, susceptible to interpretation and, accordingly, such projections may not be achieved. The internal financial projections also reflect numerous assumptions made by management, including material assumptions that may not be realized and are subject to significant uncertainties and contingencies, all of which are difficult to predict and many of which are beyond the control of the preparing party. MEP management, consistent with past presentations to the MEP GP Board and public guidance representations, develops its financial projections according to several criteria, including commodity price sensitivities. For internal purposes only, MEP management also provides financial projections that include prospective projects, which are risked based on the status of each project’s probability of success and final approval, among other factors. The financial projections that include risked prospective projects are reviewed alongside the other projections in the ordinary course. Prospective mergers and acquisitions were excluded from the financial projections. Accordingly, there can be no assurance that the assumptions made in preparing the internal financial projections upon which the foregoing projected financial information was based will prove accurate. There will be differences between actual and projected results, and the differences may be material. The risk that these uncertainties and contingencies could cause the assumptions to fail to be reflective of actual results is further increased due to the length of time in the future over which these assumptions apply.

Any inaccuracy of assumptions and projections in early periods could have a compounding effect on the projections shown for the later periods. Thus, any failure of an assumption or projection to be reflective of actual results in an early period could have a greater effect on the projected results failing to be reflective of actual events in later periods.

All of these assumptions involve variables making them difficult to predict, and some are beyond the control of MEP. Although MEP’s management believes that there was a reasonable basis for its projections and underlying assumptions, any assumptions for near-term projected cases remain uncertain, and the risk of inaccuracy increases with the length of the projected period. The projections are forward-looking statements and are subject to risks and uncertainties. See “Cautionary Statement Regarding Forward-Looking Statements.”

In developing the projections, MEP’s management made numerous material assumptions with respect to MEP and MOLP for the period from 2017 to 2020, including:

 

    organic growth opportunities, and the amounts and timing of related capital expenditures and related operational cash flows;

 

    outstanding debt during applicable periods, and the availability and cost of capital;

 

    the cash flow from existing assets and business activities;

 

    the prices and production of, and demand for, crude oil, natural gas, NGLs and other hydrocarbon products, which could impact volumes and margins;

 

    a significant decrease in the trading price of the Class A Common Units following the disclosure of the below guidance and implementation of the distribution cuts reflected therein;

 

    an equity capital raise over the next four quarters pursuant to the terms of the Subscription Agreement; and

 

    other general business, market and financial assumptions.

 

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The summarized projected financial information set forth below was based on MEP’s and MOLP’s projected results for 2017 through 2020 with respect to the Management Projections and the Forward Curve Financial Projections.

 

     Year ended December 31  
     2016(1)     2017      2018      2019      2020  
    

(unaudited)

   

(Millions of dollars, other than per

unit amounts and commodity prices)

 

Management Projections

             

Total Wellhead Volume

     1,705       1,608        1,607        1,677        1,739  

Total NGL Throughput

     72,868       68,303        67,720        73,102        77,365  

Henry Hub Natural Gas ($/MMBtu)

   $ 2.46     $ 3.63      $ 3.28      $ 3.58      $ 3.59  

WTI Crude Oil ($/Bbl)

   $ 43.32     $ 56.35      $ 61.60      $ 70.25      $ 78.86  

Ethane ($/Gal)

   $ 0.20     $ 0.29      $ 0.34      $ 0.36      $ 0.39  

Propane ($/Gal)

   $ 0.48     $ 0.68      $ 0.74      $ 0.86      $ 0.98  

Isobutane ($/Gal)

   $ 0.68     $ 0.88      $ 0.93      $ 1.07      $ 1.20  

Normal Butane ($/Gal)

   $ 0.65     $ 0.85      $ 0.91      $ 1.05      $ 1.17  

Natural Gasoline ($/Gal)

   $ 0.94     $ 1.21      $ 1.29      $ 1.48      $ 1.65  

MOLP Adjusted EBITDA(2)

   $ 178.4     $ 109.1      $ 125.9      $ 167.0      $ 215.5  

MOLP Maintenance Capital Expenditures

   $ 27.7     $ 36.9      $ 34.0      $ 39.0      $ 43.5  

MOLP Growth Capital Expenditures

   $ 28.4     $ 34.7      $ 54.3      $ 75.1      $ 86.2  

MEP Adjusted EBITDA(3)

   $ 86.4     $ 50.6      $ 59.1      $ 80.2      $ 105.1  

MEP Distributable Cash Flow

   $ 66.0 (4)    $ 12.1      $ 30.3      $ 46.5      $ 68.9  

MEP Distributable Cash Flow Per Unit

   $ 1.43     $ 0.26      $ 0.66      $ 0.14      $ 0.21  

MEP Distribution Per Unit

   $ 1.43     $ 0.00      $ 0.12      $ 0.12      $ 0.17  

Total Debt

   $ 818.5     $ 510.2      $ 508.9      $ 515.4      $ 525.2  

Forward Curve Financial Projections

             

Henry Hub Natural Gas ($/MMBtu)

     $ 3.63      $ 3.14      $ 2.87      $ 2.88  

WTI Crude Oil ($/Bbl)

     $ 56.35      $ 56.52      $ 56.07      $ 56.06  

Ethane ($/Gal)

     $ 0.29      $ 0.32      $ 0.34      $ 0.36  

Propane ($/Gal)

     $ 0.68      $ 0.66      $ 0.65      $ 0.66  

Isobutane ($/Gal)

     $ 0.88      $ 0.85      $ 0.88      $ 0.89  

Normal Butane ($/Gal)

     $ 0.85      $ 0.83      $ 0.87      $ 0.87  

Natural Gasoline ($/Gal)

     $ 1.21      $ 1.24      $ 1.24      $ 1.24  

MOLP Adjusted EBITDA(3)

     $ 109.1      $ 111.0      $ 127.9      $ 144.9  

 

(1) These amounts represent actual results for the referenced period. The amounts are unaudited. The prices reflect the average price for each of the products for 2016.
(2) Includes distributions in excess of equity earnings, which was $11.5 million for 2016. Excludes MOLP’s share of G&A abatement under an intercompany services agreement with EEP, pursuant to which EEP has agreed to reduce the amounts payable for general and administrative expenses that would have been allocable to MOLP by $25 million annually.
(3) Includes distributions in excess of equity earnings, which was $5.9 million for 2016. Excludes MEP’s share of G&A abatement.
(4) Includes $15.9 million in distributions received by MEP pursuant to the MOLP Amendment.

 

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Non-GAAP Financial Measures (as presented in the tables above):

The unaudited financial projections of MEP above include financial measures which are not GAAP measures and are not intended to be used in lieu of GAAP measures. These non-GAAP financial measures have important limitations as analytical tools because they exclude some, but not all, items that affect the most directly comparable GAAP financial measures. The items presented do not represent all items that affect comparability between the periods presented. Variations in operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions and numerous other factors. These types of variances are not separately identified in this presentation.

MEP’s non-GAAP financial measures are Adjusted EBITDA and Distributable Cash Flow. MOLP’s non-GAAP financial measure is Adjusted EBITDA. The GAAP presentation of net income (loss) and cash provided by (used in) operating activities are the GAAP measures most directly comparable to Adjusted EBITDA, and net income (loss) is the GAAP measure most directly comparable to distributable cash flow. Adjusted EBITDA represents net income before interest expense, income tax expense (benefit), depreciation and amortization, earnings from equity method investments and any other non-cash adjustments to reconcile net income to net cash provided by operating activities plus cash distributions from equity method investments. Distributable Cash Flow represents Adjusted EBITDA, as described above, adjusted to exclude cash income taxes, cash interest expense and maintenance capital expenditures and include MEP’s proportional interest in the G&A abatement from EEP and cash flows received under the MOLP Amendment. Reconciliations of forward-looking non-GAAP financial measures to comparable GAAP measures are not available due to the challenges with estimating some of the items, particularly with estimating non-cash unrealized derivative fair value losses and gains, which are subject to market variability, and therefore a reconciliation is not available without unreasonable effort.

MEP DOES NOT INTEND TO UPDATE OR OTHERWISE REVISE THE ABOVE PROSPECTIVE FINANCIAL INFORMATION TO REFLECT CIRCUMSTANCES EXISTING AFTER THE DATE SUCH PROSPECTIVE FINANCIAL INFORMATION WAS PREPARED OR TO REFLECT THE OCCURRENCE OF SUBSEQUENT EVENTS, EVEN IN THE EVENT THAT ANY OR ALL OF THE ASSUMPTIONS UNDERLYING SUCH PROSPECTIVE FINANCIAL INFORMATION ARE NO LONGER APPROPRIATE.

Opinion of Evercore Group L.L.C. – Financial Advisor to the MEP Committee

The MEP Committee retained Evercore as its financial advisor with respect to the provision of (i) financial advisory services and (ii) an opinion to the MEP Committee as to the fairness from a financial point of view to the MEP Unaffiliated Unitholders of the Merger Consideration provided for pursuant to the Merger Agreement. At the request of the MEP Committee at a meeting of the MEP Committee held on January 26, 2017, Evercore rendered its oral opinion to the MEP Committee that, as of January 26, 2017, based upon and subject to the factors, procedures, assumptions, qualifications, limitations and other matters considered by Evercore in connection with the preparation of its opinion, the Merger Consideration provided for pursuant to the Merger Agreement is fair, from a financial point of view, to the MEP Unaffiliated Unitholders. Evercore subsequently confirmed its oral opinion in the Written Opinion.

The opinion speaks only as of the date it was delivered and not as of the time the Merger will be completed or any other date. The opinion does not reflect changes that may occur or may have occurred after January 26, 2017, which could alter the facts and circumstances on which Evercore’s opinion was based. It is understood that subsequent events may affect Evercore’s opinion, but Evercore does not have any obligation to update, revise or reaffirm its opinion.

Evercore’s opinion was directed to the MEP Committee (in its capacity as such), and only addressed the fairness from a financial point of view, as of the date of the opinion, to the MEP Unaffiliated Unitholders of the Merger Consideration provided for pursuant to the Merger Agreement. Evercore’s opinion did not address any other term or aspect of the Merger Agreement or the Merger Transactions. The full text of the Written Opinion

 

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which describes the assumptions made, procedures followed, matters considered, and qualifications and limitations of the review undertaken by Evercore in rendering its opinion, is attached as Annex C to this information statement. The summary of Evercore’s opinion set forth in this information statement is qualified in its entirety by reference to the full text of the Written Opinion. However, neither the Written Opinion nor the summary of such opinion and the related analyses set forth in this information statement are intended to be, and they do not constitute, a recommendation as to how unitholders of MEP or any other person should act or vote with respect to any matter relating to the Merger Transactions or any other matter.

Evercore’s opinion to the MEP Committee was among several factors taken into consideration by the MEP Committee in making its recommendation to the MEP GP Board regarding the Merger and the Merger Agreement.

In connection with rendering its opinion and performing its related financial analyses, Evercore, among other things:

 

    reviewed certain publicly available historical business and financial information relating to MEP that Evercore deemed to be relevant, including information set forth in MEP’s Annual Report on Form 10-K for the year ended December 31, 2015, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016, June 30, 2016 and September 30, 2016 and Current Reports on Form 8-K filed since January 1, 2016, in each case as filed with or furnished to the U.S. Securities and Exchange Commission by MEP;

 

    reviewed certain non-public historical and projected financial and operating data relating to MEP prepared and furnished to Evercore by management of MEP, including the Management Projections;

 

    discussed the past and current operations, financial projections and current financial condition of MEP with management of MEP, including the Management Projections (including management’s views on the risks and uncertainties of achieving such projections);

 

    reviewed certain publicly available research analyst estimates for MEP’s future financial performance on a standalone basis;

 

    reviewed the reported prices and the historical trading activity of the Class A Common Units;

 

    compared the financial performance of MEP and its stock market trading multiples with publicly available financial terms of certain other publicly traded companies that Evercore deemed relevant;

 

    compared the financial performance of MEP and the valuation multiples implied by the Merger with those of certain other transactions that Evercore deemed relevant;

 

    performed a discounted cash flow analysis based on forecasts and other data provided by management of MEP, including the Management Projections;

 

    performed a discounted distributions analysis based on forecasts and other data provided by management of MEP, including the Management Projections;

 

    reviewed the premiums paid in certain historical transactions that Evercore deemed relevant and compared such premiums to those implied by the Merger Transactions;

 

    reviewed information regarding the process conducted by EEP with respect to soliciting third parties to acquire EEP’s general partner and limited partner interests in MEP and EEP’s limited partner interest in MOLP or alternatively, all of the general partner and limited partner interests in MEP and MOLP;

 

    reviewed a draft of the Merger Agreement dated January 25, 2017;

 

    reviewed a draft of the Support Agreement dated January 25, 2017; and

 

    performed such other analyses and examinations, reviewed such other information and considered such other factors that Evercore deemed appropriate for the purposes of providing the opinion contained herein.

 

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For purposes of its analysis and opinion, Evercore assumed and relied upon, without undertaking any independent verification of, the accuracy and completeness of all of the information publicly available, and all of the information supplied or otherwise made available to, discussed with, or reviewed by it, and Evercore assumes no liability therefor. With respect to the projected financial and operating data relating to MEP, Evercore assumed that such data was reasonably prepared on bases reflecting the best currently available estimates and good faith judgments of the management of MEP as to the future competitive, operating and regulatory environments and related financial performance of MEP under the assumptions stated therein. Among other things, Evercore took into consideration the financial impact on the holders of Class A Common Units of the projected substantial reduction in quarterly distributions payable on MEP common units reflected in the projected financial and operating data relating to MEP prepared and furnished to Evercore by management of MEP. Evercore did not express a view as to any projected financial or operating data relating to MEP or any judgments, estimates or assumptions on which such data are based. Evercore relied, at the MEP Committee’s direction, without independent verification, upon the assessments of the management of MEP as to the future financial and operating performance of MEP.

For purposes of rendering its opinion, Evercore assumed that the representations and warranties of each party contained in the Merger Agreement and the Support Agreement (in the draft forms reviewed by Evercore) are true and correct in all respects material to its analysis, that each party would perform all of the covenants and agreements required to be performed by it under the Merger Agreement and the Support Agreement and that all conditions to the consummation of the Merger Transactions will be satisfied without material waiver or modification thereof. Evercore further assumed that all governmental, regulatory or other consents, approvals or releases necessary for the consummation of the Merger Transactions will be obtained without any material delay, limitation, restriction or condition that would have an adverse effect on MEP, the consummation of the Merger or materially reduce the benefits of the Merger Transactions to the holders of MEP common units. Evercore assumed that the final versions of all documents reviewed by it in draft form would conform in all material respects to the drafts reviewed by Evercore.

Evercore neither made, nor assumed any responsibility for making, any independent valuation or appraisal of the assets or liabilities of MEP or any of its subsidiaries, nor was Evercore furnished with any such appraisals, nor has Evercore evaluated the solvency or fair value of MEP or any of its subsidiaries under any state or federal laws relating to bankruptcy, insolvency or similar matters. Evercore’s opinion is necessarily based upon information made available to it as of the date of its opinion, and financial, economic, market and other conditions as they existed and as could be evaluated on the date of Evercore’ opinion. It is understood that subsequent developments may affect Evercore’s opinion and that Evercore does not have any obligation to update, revise or reaffirm its opinion.

The estimates contained in Evercore’s analyses and the results from any particular analysis are not necessarily indicative of future results, which may be significantly more or less favorable than suggested by such analyses. In addition, analyses relating to the value of businesses or assets neither purport to be appraisals nor do they necessarily reflect the prices at which businesses or assets may actually be sold. Accordingly, Evercore’s analyses and estimates are inherently subject to substantial uncertainty.

In arriving at its opinion, Evercore did not attribute any particular weight to any particular analysis or factor considered by it, but rather made qualitative judgments as to the significance and relevance of each analysis and factor. Several analytical methodologies were employed by Evercore in its analyses, and no one single method of analysis should be regarded as determinative of the overall conclusion reached by Evercore. Each analytical technique has inherent strengths and weaknesses, and the nature of the available information may further affect the significance of particular techniques. Accordingly, Evercore believes that its analyses must be considered as a whole and that selecting portions of its analyses and of the factors considered by it, without considering all analyses and factors in their entirety, could create a misleading or incomplete view of the evaluation process underlying its opinion. The conclusion reached by Evercore, therefore, is based on the application of Evercore’s experience and judgment to all analyses and factors considered by Evercore, taken as a whole.

 

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Evercore was not asked to pass upon, and expressed no opinion with respect to, any matter other than the fairness of the Merger Consideration provided for pursuant to the Merger Agreement, from a financial point of view, as of the date of the opinion, to the MEP Unaffiliated Unitholders. Evercore did not express any view on, and its opinion does not address, the fairness, financial or otherwise, of the Merger Transactions to, or any consideration received in connection therewith by, the holders of any other securities, creditors or other constituencies of MEP, nor the fairness of the amount or nature of any compensation to be paid or payable to any of the officers, directors or employees of MEP, MEP GP or any of the other parties to the Merger Agreement or any affiliates thereof or any class of such persons, whether relative to the Merger Consideration, the Merger Transactions or otherwise. Evercore assumed that any modification to the structure of the Merger Transactions would not vary in any respect material to its analysis. Evercore’s opinion does not address the relative merits of the Merger Transactions as compared to other business or financial strategies or opportunities that might have been available to MEP, nor does it address the underlying business decision of MEP to engage in the Merger Transactions. In arriving at its opinion, Evercore was not authorized to solicit, and did not solicit, interest from any third party with respect to the acquisition of any or all of the units of MEP or any business combination or other extraordinary transaction involving MEP. Evercore’s opinion did not constitute a recommendation to the MEP Committee or to any other persons in respect of the Merger Transactions, including as to how any holder of units of MEP should vote or act in respect of the Merger Transactions. Evercore expressed no opinion therein as to the price at which the Class A Common Units would trade at any time. Evercore is not a legal, regulatory, accounting or tax expert and assumed the accuracy and completeness of assessments by MEP and its advisors with respect to legal, regulatory, accounting and tax matters.

The following is a summary of the material financial analyses performed by Evercore in connection with the preparation of its opinion and reviewed with the MEP Committee on January 26, 2017. Unless the context indicates otherwise, enterprise values and equity values used in the selected companies analysis described below were calculated using the closing price of the Class A Common Units and the equity securities of the selected companies listed below as of January 25, 2017, and transaction values for the selected transactions analysis described below were calculated on an enterprise value basis based on the value of the equity consideration and other public information available at the time of the relevant transaction’s announcement. The analyses summarized below include information presented in tabular format. In order to fully understand the financial analyses performed, the tables must be considered together with the textual summary of the analyses.

No company or transaction used in the analyses of companies or transactions summarized below is identical or directly comparable to MEP or the Merger Transactions. As a consequence, mathematical derivations (such as the high, low, mean and median) of financial data are not by themselves meaningful, and these analyses must take into account differences in the financial and operating characteristics of the selected publicly traded companies and differences in the structure and timing of the selected transactions and other factors that would affect the public trading value and acquisition value of the companies considered.

Projections

See “Special Factors—Unaudited Financial Projections of MEP and MOLP” for a description of certain non-public historical and projected financial and operating data and assumptions, relating to MEP and MOLP, prepared and furnished to Evercore by management of MEP.

Analysis of MEP

Evercore performed a series of analyses to derive indicative valuation ranges for Class A Common Units and compared each of the resulting valuation ranges to the proposed Merger Consideration.

Evercore performed its analyses utilizing (i) the Management Projections and (ii) the forward curve price case, which are referred to in this section as “Forward Curve Financial Projections.” The Management Projections and the Forward Curve Financial Projections were not adjusted by Evercore.

 

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Discounted Cash Flow Analysis

Evercore performed a discounted cash flow analysis of MEP by valuing the cash flows to be received by MEP based on the Management Projections and the Forward Curve Financial Projections. Evercore calculated the per unit value range for Class A Common Units by utilizing a range of discount rates with a mid-point equal to MEP’s Weighted Average Cost of Capital (“WACC”), as estimated by Evercore based on the Capital Asset Pricing Model (“CAPM”), and terminal values based on a range of estimated EBITDA exit multiples as well as perpetuity growth rates. Evercore assumed a range of discount rates of 9.0% to 10.0%, a range of EBITDA exit multiples of 8.0x to 10.0x, and a range of perpetuity growth rates of 2.0% to 3.0% resulting in an implied equity value per unit range of (i) $2.29 per unit to $4.88 per unit utilizing the Management Projections and (ii) ($0.07) per unit to $2.02 per unit utilizing the Forward Curve Financial Projections.

After discussions with Enbridge management regarding the issuance of Class C Units required in the Management Projections, Evercore performed sensitivity analyses assuming both (i) a range of MEP Class C Unit net issuance unit prices of $4.00 to $8.00 and (ii) no Class C Unit issuance (the “Class C Unit Sensitivity”). Utilizing a range of MEP Class C Unit net issuance unit prices of $4.00 to $8.00 resulted in an implied equity value per unit range of (i) $5.39 per unit to $7.82 per unit using the Management Projections and (ii) $1.24 per unit to $2.26 per unit using the Forward Curve Financial Projections. Assuming no Class C issuance resulted in an implied equity value per unit range of (i) $4.73 per unit to $11.35 per unit using the Management Projections and (ii) ($1.28) per unit to $4.06 per unit using the Forward Curve Financial Projections.

Discounted Distribution Analysis

Evercore performed a discounted distribution analysis of MEP based on the present value of the future cash distributions to MEP common unitholders. The projected distributions utilized by Evercore were based on the Management Projections, a terminal yield range of 15.0% to 25.0% based on trading over the last three months, a cost of equity of 17.0% to 18.5% based on CAPM and a cost of equity of 12.5% to 13.5% based on expected market total return for similar MLPs. Evercore determined an implied equity value per unit range using the cost of equity based on CAPM of $0.64 per unit to $0.91 per unit using the Management Projections and an implied equity value per unit range using the cost of equity based on market return of $0.73 per unit to $1.04 per unit utilizing the Management Projections.

 

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Precedent M&A Transaction Analysis – Asset Transactions

Evercore reviewed selected publicly available information for historical assets transactions involving natural gas gathering and processing assets announced since January 2014 and selected 25 transactions involving assets that Evercore deemed to have certain characteristics that are similar to those of MEP’s natural gas gathering and processing assets, although Evercore noted that none of the selected transactions or the selected companies that participated in the selected transactions were directly comparable to MEP:

 

Date

Announced

  

Acquiror

  

Target

  

Seller

1/4/17    DCP Midstream Partners, LP    Permian Basin, Midcontinent and DJ Basin gathering and processing assets and marketing and logistics assets    DCP Midstream, LLC
11/21/16    Tesoro Logistics LP    Bakken gathering and processing assets    Whiting Oil and Gas Corporation, GBK Investments, LLC and WBI Midstream, LLC
9/26/16    Rice Midstream Partners, LP    30 miles of dry gas gathering assets and compression assets    Rice Midstream, Inc.
7/5/16    Sanchez Production Partners LP    50% interest in Carnero Gathering, LLC    Sanchez Energy Corp
2/25/16    Summit Midstream Partners, LP    Summit Utica, Meadowlark Midstream, Tioga Midstream and 40.0% of Ohio Gathering    Summit Midstream Partners, LLC
2/24/16    Western Gas Partners, LP    Springfield Pipeline LLC    Anadarko Petroleum Corporation
12/31/15    I Squared Capital    San Juan Basin Gathering System    WPX Energy, Inc.
12/7/15    EnLink Midstream Partners, LP    Tall Oak Midstream, LLC   
11/5/15    Meritage Midstream Services IV, LLC    Rocky Mountain Infrastructure LLC    Bonanza Creek Energy, Inc.
9/28/15    Sanchez Production Partners LP    Pipeline, Gathering and Compression Assets in Western Catarina    Sanchez Production Partners LP
6/1/15    Enterprise Products Partners L.P.    50.1% interest in Eagle Ford Shale Midstream business    Pioneer Natural Resources Company
5/8/15    Southcross Energy Partners, LP    Remaining gathering, treating, compression and transportation assets    Southcross Holdings, LP
4/6/15    Williams Partners L.P.    21% equity interest in Utica East Ohio Midstream LLC    EV Energy Partners, L.P.
3/19/15    Howard Midstream Energy Partners, LLC    Northeast Pennsylvania gathering assets    Southwestern Energy Company
3/10/15    EQT Midstream Partners, LP    Northern West Virginia Marcellus Gathering System    EQT Corporation
3/3/15    Western Gas Partners, LP    50% interest in the Delaware Basin JV gathering system    Anadarko Petroleum Corporation
2/2/15    Enlink Midstream Partners, LP    Coronado Midstream Holdings LLC   

 

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1/15/15    Marlin Midstream Partners    Legacy Gathering System    Azure Midstream Energy, LLC
10/28/14    Western Gas Partners, LP    Nuevo Midstream LLC   
10/15/14    American Midstream Partners, LP    Costar Midstream LLC    Energy Spectrum Partners and Costar Management
6/19/14    Midcoast Energy Partners, L.P.    12.6% interest in Midcoast Operating, L.P.    Enbridge Energy Partners, L.P.
5/7/14    QEP Midstream Partners, LP    Green River Processing, LLC    QEP Resources, Inc.
4/30/14    EQT Midstream Partners, LP    Jupiter Natural Gas Gathering System    EQT Corporation
3/10/14    Summit Midstream Partners, LP    Red Rock Gathering Company, LLC    Summit Midstream Partners, LLC
1/22/14    American Midstream Partners, LP    Eagle Ford Shale Natural Gas Midstream Assets    Penn Virginia Corporation

Evercore reviewed the historical EBITDA multiples paid in the selected historical asset transactions and derived a range of relevant implied multiples of market value of equity, plus debt and preferred units, less cash (“Enterprise Value”) to EBITDA of 7.0x to 10.0x for the natural gas gathering and processing asset precedent transactions. Evercore then applied these ranges of selected multiples to estimated 2017 MOLP adjusted EBITDA and 2018 MOLP adjusted EBITDA. For the value implied by the Enterprise Value to EBITDA multiple, Evercore discounted valuations to a projected March 31, 2017 based on a 9.5% WACC, as appropriate, and subtracted the present value of growth capital expenditures between March 31, 2018 and March 31, 2017, as appropriate, based on the same 9.5% WACC. Utilizing the Management Projections, Evercore determined an implied equity value per unit range of $0.25 per unit to $1.77 per unit.

The Class C Unit Sensitivity resulted in an implied equity value per unit range of $1.68 per unit to $2.04 per unit assuming MEP Class C Unit net issuance unit prices of $4.00 to $8.00 and an implied equity value per unit range of ($0.47) per unit to $3.42 per unit assuming no Class C Unit issuance, utilizing the Management Projections.

Precedent M&A Transaction Analysis – Corporate Transactions

Evercore reviewed selected publicly available information for historical corporate transactions involving natural gas gathering and processing publicly traded entities announced since January 2013 and selected 8 transactions involving MLPs that Evercore deemed to have certain characteristics similar to MEP, although Evercore noted that none of the selected transactions or the selected companies that participated in the selected transactions were directly comparable to MEP:

 

Date

Announced

  

Acquiror

  

Target

7/13/15

   MPLX LP    MarkWest Energy Partners, L.P.

5/6/15

   Crestwood Equity Partners LP    Crestwood Midstream Partners LP

4/6/15

   Tesoro Logistics LP    QEP Midstream Partners, LP

1/26/15

   Energy Transfer Partners, L.P.    Regency Energy Partners LP

10/13/14

   Targa Resource Partners LP    Atlas Pipeline Partners, L.P.

10/10/13

   Regency Energy Partners LP    PVR Partners, L.P.

5/6/13

   Inergy Midstream, L.P.    Crestwood Midstream Partners LP

1/29/13

   Kinder Morgan Energy Partners, L.P.    Copano Energy, L.L.C.

Evercore reviewed the historical EBITDA multiples paid in the selected historical corporate transactions and derived a range of relevant implied multiples of Enterprise Value to EBITDA of (i) 12.5x to 15.0x for 2017 MOLP adjusted EBITDA and (ii) 10.0x to 12.0x for 2018 MOLP adjusted EBITDA. Evercore then applied these

 

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ranges of selected multiples to estimated 2017 MOLP adjusted EBITDA and 2018 MOLP adjusted EBITDA and determined an implied equity value per unit range of $2.42 per unit to $4.07 per unit using the Management Projections.

The Class C Unit Sensitivity resulted in an implied equity value per unit range of $5.40 per unit to $6.54 per unit assuming MEP Class C Unit net issuance unit prices of $4.00 to $8.00 and an implied equity value per unit range of $5.06 per unit to $9.30 per unit assuming no Class C Unit issuance, utilizing the Management Projections.

Peer Group Trading Analysis

Evercore performed a peer group trading analysis of MEP by reviewing and comparing the market values and trading multiples of the following 15 MLPs that Evercore deemed to have certain characteristics that are similar to those of MEP, including size and asset base, divided into (i) gathering and processing MLPs with commodity price sensitivity / producer volume exposure, and (ii) other gathering and processing MLPs:

Gathering and Processing MLPs with Commodity Price Sensitivity / Producer Volume Exposure:

 

    American Midstream Partners, LP

 

    Azure Midstream Partners, LP

 

    Crestwood Equity Partners LP

 

    DCP Midstream Partners, LP

 

    Enable Midstream Partners, LP

 

    Southcross Energy Partners, L.P.

Other Gathering and Processing MLPs:

 

    Antero Midstream Partners LP

 

    CONE Midstream Partners LP

 

    EnLink Midstream Partners, LP

 

    Noble Midstream Partners LP

 

    PennTex Midstream Partners, LP

 

    Rice Midstream Partners LP

 

    Summit Midstream Partners, LP

 

    Tallgrass Energy Partners, LP

 

    Western Gas Partners, LP

Although the peer group was compared to MEP for purposes of this analysis, no MLP used in the peer group analysis is identical or directly comparable to MEP. In order to calculate peer group trading multiples, Evercore relied on publicly available filings with the SEC and equity research analyst estimates.

For each of the peer group MLPs, Evercore calculated the following trading multiples:

 

    Enterprise Value/2017 EBITDA, which is defined as Enterprise Value, divided by estimated EBITDA for the calendar year 2017; and

 

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    Enterprise Value/2018 EBITDA, which is defined as Enterprise Value divided by estimated EBITDA for the calendar year 2018.

The mean and median trading multiples are set forth below. The table also includes relevant multiple ranges selected by Evercore based on the resulting range of multiples and certain other considerations related to the specific characteristics of MEP noted by Evercore.

 

Benchmark (Gathering & Processing MLPs with Commodity

Price Sensitivity/Producer Volume Exposure)

   Mean      Median  

Enterprise Value/2017 EBITDA

     11.2x        11.3x  

Enterprise Value/2018 EBITDA

     10.3x        10.8x  

Benchmark (Other Gathering & Processing MLPs)

   Mean      Median  

Enterprise Value/2017 EBITDA

     11.9x        11.6x  

Enterprise Value/2018 EBITDA

     9.7x        9.5x  

 

Benchmark (Management Projections)

   Reference Range  

Enterprise Value/2017 MOLP Adjusted EBITDA

     10.0x—12.0x  

Enterprise Value/2018 MOLP Adjusted EBITDA

     9.5x—11.5x  

Utilizing the multiples illustrated above, Evercore determined an implied equity value per unit range of $1.68 per unit to $3.24 per unit using the Management Projections.

The Class C Unit Sensitivity resulted in an implied equity value per unit range of $4.10 per unit to $4.96 per unit assuming MEP Class C Unit net issuance unit prices of $4.00 to $8.00 and an implied equity value per unit range of $3.19 per unit to $7.17 per unit assuming no Class C Unit issuance, utilizing the Management Projections.

Premiums Paid Analysis

Evercore also reviewed selected publicly available information for valuation of MEP common units based on historical premiums paid in (i) MLP merger transactions generally, and (ii) MLP buy-in transactions specifically. Evercore considered that historically, MLP merger and buy-in premiums have varied widely based on specific considerations with respect to each transaction, with a range for MLP buy-in transactions of 0.0% to 23.0% premium to one-day trailing price and a median premium for MLP buy-in transactions of 15.0%. Evercore noted that none of the selected transactions or the selected MLPs or companies that participated in the selected transactions were directly comparable to the Merger or MEP.

The selected transactions and resulting minimum, maximum, mean and median data were as follows:

 

          Transaction      Premium  
Date             Equity      Enterprise                     

Announced

  

Acquiror(s) / Target

  

Consideration

 

Value

    

Value

    

1-Day

   

10-Day

   

30-Day

 

11/20/16

   Sunoco Logistics Partners LP / Energy Transfer Partners LP    Unit-for-Unit   $ 21,318.7      $ 52,363.7        (0.2 %)      17.4     7.8

11/01/16

   Columbia Pipeline Group, Inc. / TransCanada Corporation / Columbia Pipeline Partners LP    Cash-for-Unit*     915.3        2,668.7        6.3     4.3     5.3

10/24/16

   American Midstream Partners, LP / JP Energy Partners LP    Unit-for-Unit     304.9        455.0        14.5     14.8     12.1

 

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08/01/16

   Transocean Ltd. / Transocean Partners LLC    Stock-for-Unit*     862.8        1,605.0        15.0     3.2     (3.2 %) 

05/30/16

   SemGroup Corporation / Rose Rock Midstream, L.P.    Stock-for-Unit*     906.5        1,669.9        0.0     16.8     39.0

11/03/15

   Targa Resources Corp. / Targa Resources Partners LP    Stock-for-Unit*     6,673.1        7,216.2        18.4     11.0     14.9

10/26/15

   Western Refining, Inc. / Northern Tier Energy LP    Cash/Stock-for-Unit*     2,513.6        2,746.4        14.0     11.5     12.7

07/13/15

   MPLX LP / MarkWest Energy Partners, L.P.    Unit-for-Unit     15,736.0        19,956.0        31.6     36.6     29.8

05/13/15

   The Williams Companies, Inc. / Williams Partners L.P.    Stock-for-Unit*     34,237.6        54,142.3        17.9     11.8     13.5

05/06/15

   Crestwood Equity Partners LP / Crestwood Midstream Partners LP    Unit-for-Unit*     3,532.6        6,251.3        17.2     20.1     27.6

01/26/15

   Energy Transfer Partners, L.P. / Regency Energy Partners LP    Unit-for-Unit     11,155.6        17,955.6        13.2     23.2     10.6

10/27/14

   Access Midstream Partners LP / Williams Partners L.P.    Unit-for-Unit     25,925.8        37,006.8        6.5     15.6     8.4

10/13/14

   Targa Resource Partners LP / Atlas Pipeline Partners, L.P.    Unit-for-Unit     4,065.4        5,908.8        15.0     8.1     3.0

10/01/14

   Enterprise Products Partners L.P. / Oiltanking Partners L.P.    Unit-for-Unit     5,823.0        6,051.0        5.6     1.9     6.8

08/10/14

   Kinder Morgan, Inc. / Kinder Morgan Energy Partners, L.P.    Stock-for-Unit*     36,689.1        58,551.1        12.0     6.9     10.7

08/10/14

   Kinder Morgan, Inc. / El Paso Pipeline Partners, L.P.    Stock-for-Unit*     5,288.5        10,021.5        15.4     8.9     7.3

10/10/13

   Regency Energy Partners LP / PVR Partners, L.P.    Unit-for-Unit     3,899.3        5,664.3        25.6     23.7     23.7

08/27/13

   Plains All American Pipeline, L.P. / PAA Natural Gas Storage LP    Unit-for-Unit*     1,713.6        2,271.9        8.5     11.9     7.2

05/07/13

   Pioneer Natural Resources Company / Pioneer Southwest Energy Partners L.P.    Stock-for-Unit*     933.0        1,086.0        23.0     27.5     9.6

05/06/13

   Inergy Midstream, L.P. / Crestwood Midstream Partners LP    Unit-for-Unit     1,614.7        2,402.0        4.6     13.1     8.1

01/29/13

   Kinder Morgan Energy Partners, L.P. / Copano Energy, L.L.C.    Unit-for-Unit     3,777.5        4,724.3        21.8     22.5     36.7

02/23/11

   Enterprise Products Partners L.P. / Duncan Energy Partners L.P.    Unit-for-Unit     2,405.0        3,302.8        27.9     29.6     27.4

 

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All Transactions

 
  

*  MLP Buy-In Transaction

         Median      14.7     13.9     10.7
            Mean      14.3     15.5     14.5
            Max      31.6     36.6     39.0
            Min      (0.2 %)      1.9     (3.2 %) 
                       

MLP Buy-Ins

 
            Median      15.0     11.5     10.7
            Mean      13.4     12.2     13.1
            Max      23.0     27.5     39.0
            Min      0.0     3.2     (3.2 %) 

Based on the relevant median premiums, Evercore calculated implied equity value per unit ranges of: (i) $7.59 to $10.18 for MLP buy-in transactions and (ii) $7.52 to $10.18 for all MLP merger transactions.

Other Written Presentations by Evercore

In addition to the presentation made to the MEP Committee on January 26, 2017, the date on which Evercore delivered its fairness opinion, as described above, Evercore made other written and oral presentations to the MEP Committee on December 20, 2016 and on January 9 and January 24 of 2017. Copies of these other written presentations by Evercore to the MEP Committee have been attached as exhibits to the Transaction Statement on Schedule 13E-3 filed with the SEC with respect to the proposed Merger. These written presentations will be available for any interested unitholder of MEP to inspect and copy at MEP’s executive offices during regular business hours.

None of these other written and oral presentations by Evercore, alone or together, constitutes an opinion of Evercore with respect to the Merger Consideration. The information contained in the written and oral presentation made to the MEP Committee on December 20, 2016 and on January 24, 2017 is substantially similar to the information provided in Evercore’s written presentation to the MEP Committee on January 26, 2017, as described above, and the information contained in the written presentation on January 9, 2017 is intended to supplement the information contained in Evercore’s presentation on December 20, 2016.

The December 20 materials contained a review of the proposed transaction based on Enbridge’s initial offer of $6.25 per Class A Common Unit, including (1) a summary of the terms of the Merger, (2) a situation analysis for MEP, including an overview of MEP’s recent trading performance, (3) a detailed overview of MEP’s assets and operations, including MOLP, (4) a summary of the Management Projections, including the underlying assumptions, (5) a detailed preliminary financial analysis of MEP and (6) an overview of potential standalone alternatives for MEP. The potential standalone alternatives considered include (1) the indications of interest received during the recent Sale Process, including Company A’s proposed acquisition of MOLP’s interest in the Texas Express NGL system, (2) a distribution reduction or elimination and (3) the execution and delivery by MEP of the Subscription Agreement and the issuance of Class C units with the proceeds utilized to repay debt. It was determined that the standalone alternatives were either not feasible or would likely result in suboptimal outcomes for the MEP Unaffiliated Unitholders due to the following reasons: (1) there was limited interest in the Sale Process with no final, binding bids, (2) commodity prices would need to recover dramatically in order to maintain a distribution and precedent situations suggest that a distribution reduction would result in a material reduction in the Class A Common Unit trading price unless the distribution reduction was announced in connection with another positive event for MEP and (3) the distribution received by MEP from MOLP would not be sufficient to cover continued distributions by MEP following the issuance of Class C units, even when considering the benefit to MEP of the MOLP Amendment which would expire on December 31, 2017.

In the December 20 materials, the discounted cash flow analysis assumed (1) an EBITDA exit multiple of 8.0x to 9.0x, (2) a perpetuity growth rate of 2.0% to 3.0%, (3) a WACC range of 9.5% to 10.5% based on the

 

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capital asset pricing model and (4) a March 31, 2017 transaction date, which resulted in an implied equity value range of $1.65 to $3.69 per Class A Common Unit as compared to the $6.25 per Class A Common Unit offer at the time. The discounted distribution analysis assumed a terminal yield range of 15.0% to 25.0% for the projected distributions based on the Management Projections with two different cost of equity scenarios (1) a cost of equity of 21.0% to 22.0% based on the capital asset pricing model, which resulted in an implied equity value range of $0.58 to $0.82 per Class A Common Unit as compared to the $6.25 per Class A Common Unit offer at the time, and (2) a cost of equity of 11.5% to 12.5% based on the expected total return for similar MLPs, which resulted in an implied equity value range of $0.75 to $1.07 per Class A Common Unit as compared to the $6.25 per Class A Common Unit offer at the time. The precedent M&A transaction analysis assumed (1) an Enterprise Value to current year EBITDA multiple range of 7.0x to 10.0x applied to 2017E EBITDA and (2) an Enterprise Value to 2018E EBITDA multiple range of 7.0x to 10.0x applied to 2018E EBITDA, with the resulting values discounted at a 10.0% midpoint WACC discount rate to the assumed March 31, 2017 transaction date, which resulted in an implied equity value range of ($0.07) to $1.57 per Class A Common Unit as compared to the $6.25 per Class A Common Unit offer at the time. The peer group trading analysis assumed (1) an Enterprise Value to EBITDA multiple range of 9.5x to 11.5x applied to 2017E EBITDA and (2) an Enterprise Value to EBITDA multiple range of 9.5x to 10.5x applied to 2018E EBITDA, which resulted in an implied equity value range of $0.98 to $2.39 per Class A Common Unit as compared to the $6.25 per Class A Common Unit offer at the time. The premiums paid analysis utilizing MLP Buy-Ins assumed (1) a historical 1-Day MLP merger premium range of 13.0% to 17.0%, (2) a historical 10-Day MLP merger premium range of 10.0% to 14.0% and (3) a historical 30-Day MLP merger premium range of 10.0% to 14.0%, applied to 1-Day, 10-Day and 30-Day Class A Common Unit trading prices, respectively, which resulted in an implied equity value range of $6.60 to $7.98 per Class A Common Unit as compared to the $6.25 per Class A Common Unit offer at the time. The premiums paid analysis utilizing all MLP transactions assumed (1) a historical 1-Day MLP merger premium range of 13.0% to 17.0%, (2) a historical 10-Day MLP merger premium range of 11.0% to 15.0% and (3) a historical 30-Day MLP merger premium range of 9.0% to 13.0%, applied to 1-Day, 10-Day and 30-Day MEP unit prices, respectively, which resulted in an implied equity value range of $6.66 to $7.91 per Class A Common Unit as compared to the $6.25 per Class A Common Unit offer at the time. The closing price of the Class A Common Units as of December 16, 2016 was $7.05.

The January 9 materials contained a review of Enbridge’s revised offer price set forth in the January 8 Proposal, which proposed merger consideration based off of a 30-day VWAP of the Class A Common Units as of the execution date of the Merger Agreement, which would have been $6.70 per Class A Common Unit as of January 8, 2017. The January 9 materials presented a range of potential merger consideration from $6.25 per Class A Common Unit, which was Enbridge’s original offer, to $7.75 per Class A Common Unit as a percent premium or discount to the 10-day, 20-day and 30-day VWAPs for the Common Units as of January 6, 2017 and the 52-week high for the Class A Common Units as of January 4, 2017. The following table summarizes Enbridge’s original offer and the January 8 Proposal per Class A Common Unit premium to various historical prices:

 

     Original Offer
(12/5/16)
    January 8 Offer (1/8/17)
from the January 9
Materials
 

Offer Price per MEP Unit

   $ 6.25     $ 6.70  

Premium / (Discount) to:

    

Current Price as of January 6, 2017 ($7.58)

     (17.5 %)      (11.5 %) 

10-Day VWAP as of January 6, 2017 ($7.12)

     (12.2 %)      (5.8 %) 

20-Day VWAP as of January 6, 2017 ($7.03)

     (11.1 %)      (4.7 %) 

30-Day VWAP as of January 6, 2017 ($6.70)

     (6.7 %)      0.0

52-Week High ($9.89 on January 4, 2016)

     (36.8 %)      (32.3 %) 

The January 24 materials contained a review of the MEP Committee’s January 11 Counteroffer, which proposed merger consideration per Class A Common Unit equal to the greater of (1) $7.70, the closing price of the Class A Common Units on January 11, 2017, and (2) the trading price of the Class A Common Units as of the

 

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execution of the Merger Agreement, and followed the same format as the December 20 materials except that the January 24 and 26 materials reflected the Sensitivity Analysis and demonstrated how Evercore’s financial analyses changed if Class C Unit issuances assumed in the Management Projections were (i) consummated at higher per unit purchase prices or (ii) were not consummated. Materials presented by Evercore prior to and including January 26 utilized identical forward multiples of 7.0x to 10.0x applied to 2017E EBITDA and 2018E EBITDA in the asset precedent M&A transactions analysis, with the resulting valuation adjusted for capital expenditures incurred and discounted at the midpoint weighted average cost of capital. The implied valuation ranges in the January 24 materials are materially the same as those used in the January 26 materials, except for the corporate precedent M&A transactions analysis, for which the January 24 materials utilize current year multiples of 13.5x to 16.0x for 2017E and 2018E EBITDA (with the 2018 values discounted back to March 31, 2017), respectively, and the January 26 Materials include an adjustment in methodology for the corporate precedent M&A transactions analysis to utilize distinct current year multiples of 12.5x to 15.0x and one-year forward multiples of 10.0x to 12.0x for 2017E EBITDA and 2018E EBITDA (without discounting 2018 values back to March 31, 2017), respectively. The implied valuation ranges for the corporate precedent M&A transactions analysis assuming the Class C Unit issuances were consummated at a price of $1.38 per Class C Unit were $3.36 to $4.79 for the January 24 materials and $2.42 to $4.07 for the January 26 materials. The implied valuation ranges for the corporate precedent M&A transactions analysis assuming the Class C Unit issuances were consummated at higher per unit purchase prices, as described above, were $6.78 to $8.21 for the January 24 materials and $5.40 to $6.54 for the January 26 materials. The implied valuation ranges for the corporate precedent M&A transactions analysis assuming no Class C Unit issuances were consummated were $7.47 to $11.14 for the January 24 materials and $5.06 to $9.30 for the January 26 materials.

Evercore used the Management Projections in its written and oral presentations to the MEP Committee on December 20, 2016 and on January 24 and January 26 of 2017. These written and oral presentations made by Evercore contained, among other things, the following types of financial analyses:

 

    a discounted cash flow analysis;

 

    a discounted distribution analysis;

 

    a precedent M&A transaction analysis;

 

    a peer group trading analysis; and

 

    a premiums paid analysis.

Not all of the written and oral presentations made by Evercore contained all of the financial analyses listed above. The financial analyses in Evercore’s written and oral presentations were based on market, economic and other conditions as they existed as of the dates of the respective presentations as well as other information that was available at those times. Accordingly, the results of the financial analyses differed due to changes in those conditions.

General

Evercore and its affiliates engage in a wide range of activities for their own accounts and the accounts of customers. In connection with these businesses or otherwise, Evercore and its affiliates and/or their respective employees, as well as investment funds in which any of them may have a financial interest, may at any time, directly or indirectly, hold long or short positions and may trade or otherwise effect transactions for their own accounts or the accounts of customers, in debt or equity securities, senior loans and/or derivative products relating to MEP and its affiliates.

Evercore and its affiliates also engage in securities trading and brokerage, private equity and investment management activities, equity research and other financial services, and in the ordinary course of these activities, Evercore and its affiliates may from time to time acquire, hold or sell, for their own accounts and for the accounts of their customers, (i) equity, debt and other securities (or related derivative securities) and financial instruments

 

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(including bank loans and other obligations) of MEP and (ii) any currency or commodity that may be involved in the Merger Transactions and the other matters contemplated by the Merger Agreement.

Evercore and its affiliates and certain of its employees, including members of the team performing services in connection with the Merger Transactions, as well as certain private equity or other investment funds associated or affiliated with Evercore in which they may have financial interests, may from time to time acquire, hold or make direct or indirect investments in or otherwise finance a wide variety of companies, including MEP, other actual or potential transaction participants and their respective affiliates.

The MEP Committee selected Evercore to provide financial advice in connection with its evaluation of the merger because of, among other reasons, Evercore’s experience, reputation and familiarity with the midstream sector of the energy industry and because its investment banking professionals have substantial experience in transactions similar to the Merger.

Evercore expressly consented to the inclusion in their entirety of its opinion and the materials it presented to the MEP Committee as exhibits to the transaction statement on Schedule 13E-3.

The description set forth above constitutes a summary of the analyses employed and factors considered by Evercore in rendering its opinion to the MEP Committee. The preparation of a fairness opinion is a complex, analytical process involving various determinations as to the most appropriate and relevant methods of financial analysis and the application of those methods to the particular circumstances and is not necessarily susceptible to partial analysis or summary description.

Pursuant to the terms of the engagement of Evercore, Evercore will receive a fee of $2.0 million for its services, of which $1.0 million became payable upon the execution of its engagement letter and $1.0 million became payable upon the rendering of the opinion. In addition, MEP has agreed to reimburse certain of Evercore’s expenses and indemnify Evercore and certain related parties against certain liabilities arising out of its engagement.

During the two-year period prior to the date of Evercore’s opinion, Evercore was engaged by the MEP Committee in connection with the contemplated the Equity Commitment, for which it was paid $263,922.23. Other than with respect to these matters, no material relationship existed between Evercore or any of its affiliates, on the one hand, and MEP, EEP, MEP GP, or EECI or any of their respective affiliates, on the other hand, pursuant to which compensation was received or is intended to be received by Evercore or its affiliates as a result of such relationship. Evercore and its affiliates may provide financial or other services to MEP, EEP, MEP GP, or EECI or any of their respective affiliates in the future and in connection with any such services Evercore may receive compensation.

EEM Conflicts Committee and the EEM Board

On January 26, 2017, the EEM Conflicts Committee, consisting of three independent directors, unanimously (1) determined based upon the facts and circumstances it deemed relevant, reasonable or appropriate to its decision, including its review of the terms of the Merger Agreement and the Merger Transactions, that the Merger Agreement and the Merger Transactions is fair and reasonable to, and in the best interests of, EEP including the EEP Unaffiliated Unitholders, (2) recommended, on behalf of EEP, that the EEM Board cause EEP to (A) exercise EEP’s power, as the sole member of MEP GP, to approve the Merger and the transactions contemplated thereby, including the adoption and approval of the Merger Agreement and the Support Agreement, (B) vote or deliver a written consent in favor of EEP’s limited partner interests in MEP in favor of the Merger and the transactions contemplated thereby and (C) enter into the Support Agreement.

Acting in part based on the recommendation of the EEM Conflicts Committee, the EEM Board (1) determined that each of the Merger, the Merger Agreement and the Merger Transactions is fair and reasonable to and in the best

 

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interests of EEP, including its partners, (2) authorized and approved the voting or consent by EEP, (A) as the sole member of MEP GP and (B) of the Units held by EEP, in favor of the Merger and the adoption and approval of the Merger Agreement, and (3) authorized and approved the Support Agreement.

Position of the Enbridge Parties, the MEP GP Board and the MEP Committee as to the Fairness of the Merger

Under the rules governing “going private” transactions, each of Enbridge, EEP, EEM, EECI and Merger Sub (collectively, the “Enbridge Parties”) are deemed to be engaged in a “going private” transaction and are required to express their beliefs as to the fairness of the Merger to the MEP Unaffiliated Unitholders pursuant to Rule 13e-3 under the Exchange Act. The Enbridge Parties, the MEP Committee and the MEP GP Board are making the statements included in this section solely for the purposes of complying with the requirements of Rule 13e-3 and related rules under the Exchange Act. The MEP GP Board delegated to the MEP Committee the power and authority to review, evaluate and make a recommendation to the MEP GP Board with respect to the proposed transaction, which included the power to negotiate, or delegate to any person the ability to negotiate, the terms and conditions of the proposed transaction and to determine whether the proposed transaction is advisable and fair to, and in the best interests of, MEP and the MEP Unaffiliated Unitholders.

None of Enbridge, EEP, EEM, EECI or Merger Sub undertook an independent evaluation of the fairness of the Merger to the MEP Common Unitholders or engaged a financial advisor for such purpose. However, such entities and MEP and MEP GP believe that the Merger is substantively and procedurally fair to the MEP Unaffiliated Unitholders based on the procedural safeguards implemented during the negotiation of the Merger Agreement, which include the authorization of the MEP Committee to (1) review and to evaluate the terms and conditions of the proposed transaction on behalf of the MEP Unaffiliated Unitholders and MEP; (2) negotiate, or delegate to any person or persons the ability to negotiate, the terms and conditions of the proposed transaction; (3) determine whether or not to recommend for approval to the MEP GP Board the proposed transaction, any such recommendation of such transaction made in good faith to constitute “Special Approval” as such term is defined in the MEP Partnership Agreement; (4) to determine whether the proposed transaction is advisable and fair to, and in the best interests of, MEP, MEP’s subsidiaries and the MEP Unaffiliated Unitholders; (5) approve any actions or agreements and other documents as the MEP Committee may deem necessary, appropriate or advisable in connection with the exercise of its authority; and (6) direct the officers of MEP GP to negotiate, execute and deliver, and to cause the performance of, or waiver of rights under, any such agreements and other documents as may be necessary for the MEP Committee to perform its functions, and the other factors considered by, and the analysis, discussion and resulting conclusions of the MEP Committee and the MEP GP Board described in the section entitled “—Recommendation of the MEP Committee and the MEP GP Board; Reasons for Recommending Approval of the Merger Agreement and the Merger Transactions,” which analysis, discussion and resulting conclusions such entities expressly adopt as their own.

The foregoing discussion of the information and factors considered and given weight by the Enbridge Parties, the MEP GP Board and the MEP Committee is not intended to be exhaustive, but includes the factors considered by the Enbridge Parties, the MEP GP Board and the MEP Committee that each believes to be material to the fairness determination regarding the fairness of the Merger for the purpose of complying with the requirements of Rule 13e-3 and the related rules under the Exchange Act. The Enbridge Parties, the MEP GP Board and the MEP Committee did not find it practicable to, and did not, quantify or otherwise attach relative weights to the foregoing factors in reaching their position as to the fairness of the Merger. Rather, the Enbridge Parties, the MEP GP Board and the MEP Committee made their fairness determination after considering all of the factors as a whole.

Enbridge Parties’ Purpose and Reasons for the Merger

The Enbridge Parties’ reasons for the Merger include, but are not limited to:

 

   

A Simplified Corporate Governance: The Merger will result in Enbridge ultimately owning all of the equity interests MEP through the holdings of its affiliates EEP and EECI. The transaction will enable

 

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Enbridge to focus on managing for itself and for EEP their respective equity holder bases, dividend policies, growth stories, costs, debt ratings and structural subordination of indebtedness within the corporate family.

 

    Increased Ownership in MEP: Following the consummation of the Merger, EECI will own approximately 48% of the limited partner interests in MEP, and EEP will own the remaining approximate 52% of the limited partner interests and 2% general partner interest in MEP. This is expected to allow operational synergies to occur through the streamlining of general and administrative expenses and eliminated costs associated with the Class A Common Units being publicly traded.

 

    Repositioning of EEP: The fundamentals of MEP’s underlying business have changed due to declines in natural gas, NGL and crude oil prices and related decreases in producer activity. The decline in MEP’s performance has impacted EEP’s cost of capital. These factors make it impractical for MEP to serve as a drop down vehicle for EEP’s assets.

The Enbridge Parties have undertaken to pursue the Merger at this time for the reasons described above.

The Enbridge Parties believe that structuring the transaction as a merger transaction is preferable to other transaction structures because (1) it will enable EECI to acquire all of the outstanding Class A Common Units held by the MEP Unaffiliated Unitholders at the same time, (2) it represents an opportunity for the MEP Unaffiliated Unitholders to receive cash for their Class A Common Units in the form of the Merger Consideration. EEP owns a sufficient number of common units to approve the Merger Agreement and the Merger Transactions on behalf of the holders of MEP common units without the need to solicit the approval of other MEP common unitholders, which provides greater deal certainty. Further, the Enbridge Parties believe that structuring the transaction as a merger transaction provides a prompt and orderly transfer of ownership of MEP in a single step, without the necessity of financing separate purchases of the Class A Common Units in a tender offer and implementing a second-step merger to acquire any Class A Common Units not tendered into any such tender offer, and without incurring any additional transaction costs associated with such activities.

The foregoing discussion of the information and factors considered by the Enbridge Parties is not intended to be exhaustive, but includes the material factors considered by the Enbridge Parties. In view of the variety of factors considered in connection with its evaluation of the Merger, the Enbridge Parties did not find it practicable to, and did not, quantify or otherwise assign relative weights to the specific factors considered in reaching its determination and recommendation. In addition, individual directors may have given different weights to different factors. The Enbridge Parties did not undertake to make any specific determination as to whether any factor, or any particular aspect of any factor, supported or did not support its ultimate determination. The Enbridge Board based its recommendation on the totality of the information presented.

Portions of this explanation of the reasons for the Merger and other information presented in this section are forward-looking in nature and, therefore, should be read in light of the section entitled “Cautionary Statement Regarding Forward-Looking Statements.”

Effects of the Merger

Pursuant to the Merger Agreement, Merger Sub, a wholly owned subsidiary of EECI, will merge with and into MEP, with MEP surviving the Merger and continuing to exist as a Delaware limited partnership, and each Class A Common Unit issued and outstanding immediately prior to the Effective Time, other than Class A Common Units held by EECI, EEP and their respective affiliates will be converted into the right to receive $8.00 in cash, without interest. If the Merger is completed, (1) MEP Unaffiliated Unitholders will no longer have an equity interest in MEP, (2) the Class A Common Units will no longer be listed on the NYSE, (3) the registration of the Class A Common Units under the Exchange Act will be terminated and (4) EECI will own approximately 48% of the limited partner interests in MEP and EEP will own the remaining approximate 52% of the limited partner interests and 2% general partner interest in MEP.

 

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The limited liability company interests in Merger Sub issued and outstanding immediately prior to the Effective Time will be converted automatically into the number of Class A Common Units of MEP equal to the number of Class A Common Units converted into the right to receive the Merger Consideration. At the Effective Time, the books and records of MEP will be revised to reflect that all limited partners of MEP immediately prior to the Effective Time whose Class A Common Units are converted into the right to receive the Merger Consideration cease to be limited partners of MEP and that, immediately following the Effective Time, EECI and EEP will be the only limited partners of the surviving entity.

The general partner interest, the incentive distribution rights and any units owned by EEP issued and outstanding as of immediately prior to the Effective Time will be unaffected by the Merger and will remain outstanding and no consideration will be paid or delivered in respect of such partnership interests. Any partnership interests in MEP (other than the general partner interests, the incentive distribution rights and the common units owned by EEP) that are owned immediately prior to the Effective Time by MEP or any subsidiary of MEP or by EECI or any affiliate of EECI (other than MEP, MEP GP and their subsidiaries) will be automatically cancelled and cease to exist. No consideration will be delivered for such cancelled partnership interests.

As a result and upon consummation of the Merger, MEP will cease to be a publicly traded MLP and MEP’s Class A Common Units will no longer be traded on the NYSE. The current unitholders of MEP (other than EEP) will no longer have any interest in MEP’s future earnings or growth. The Merger will have the federal tax consequences described under “Material U.S. Federal Income Tax Considerations” beginning on page 72.

As a result and upon consummation of the Merger, MEP will be owned approximately 54% by EEP and approximately 46% by EECI. The following table sets forth, among other things, the number of units representing partnership interests owned directly (unless otherwise noted) by each affiliate of MEP involved in the Merger Transactions pre- and post-Merger, as well as such entity’s interest in the net book value and net earnings of MEP.

 

    Pre-Merger     Post-Merger  
    Units (1)     Interest in
Net  Book
Value (2)
    Percentage
Interest In
Net Book
Value
    Interest in
Net Loss (3)
    Percentage
Interest in
Net Loss
    Units (1)     Interest in
Net Book
Value (2)
    Percentage
Interest in
Net Book
Value
    Interest in
Net Loss (3)
    Percentage
Interest in
Net Loss
 
          (in millions)           (in millions)                 (in millions)           (in millions)        

Enbridge Energy Partners, L.P. (4)

    24,867,971     $ 1,055.9       71.8   $ (53.89     53.94     24,867,971     $ 1,055.9       71.8   $ (53.89     53.94

Enbridge Energy Company, Inc. (5)

        $       0.00   $       0.00     21,275,000     $ 414.8       28.2   $ (46.01     46.06

 

(1) Includes Class A Common Units, Class B common units and general partner units.
(2) Represents the $1,470.7 million aggregate Partners’ Capital as of December 31, 2016 in MEP, excluding non-controlling interests, allocated with respect to the Class A Common Units, Class B common units, subordinated units and general partner units.
(3) Represents the $99.9 million net loss of MEP as of December 31, 2016, allocated with respect to the Class A Common Units, Class B common units, subordinated units and general partner units.
(4) As of December 31, 2016, EEP owned 22,610,056 subordinated units, which converted into Class B common units on a one-for-one basis on February 15, 2017. Prior to the Merger, EEP owns 1,335,056 Class A Common Units, 22,610,056 Class B common units and indirectly owns 922,859 general partner units, and EEP’s unit ownership will remain unchanged as a result of the Merger.
(5) After giving effect to the Merger, EECI will own 21,275,000 Class A Common Units.

 

 

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Primary Benefits and Detriments of the Merger

Benefits and Detriments to MEP Unaffiliated Unitholders

The primary benefits of the Merger to MEP Unaffiliated Unitholders that will not have a continuing interest in MEP following the Merger include the following:

 

    The receipt by such common unitholders of $8.00 per Class A Common Unit in cash, without interest.

 

    The avoidance of all downside risk associated with the continued ownership of Class A Common Units following the Merger, including any possible decrease in the future revenues and free cash flow, growth or value of MEP resulting from the expected continued declining financial condition. In addition, absent the Merger, EEP would likely be required to take certain actions to support MEP’s financial condition, including a significant reduction in or elimination of MEP’s quarterly distributions and/or significant equity infusions by EEP, each of which would likely negatively affect the existing MEP unitholders.

The primary detriments of the Merger to MEP Unaffiliated Unitholders that will not have a continuing interest in MEP following the Merger include the following:

 

    The MEP unit price had historically traded higher for a significant portion of its trading history.

 

    Such unitholders will cease to have an interest in MEP and, therefore, will no longer benefit from possible increases in the future revenues and free cash flow, growth or value of MEP or payment of distributions on Class A Common Units, if any.

 

    In general, the receipt of cash pursuant to the Merger will be a taxable transaction for U.S. federal income tax purposes and may also be a taxable transaction under applicable state, local and foreign tax laws. As a result, a holder of Class A Common Units that receives cash in exchange for such Class A Common Units in the Merger generally will be required to recognize taxable income, gain or loss as a result of the Merger for U.S. federal income tax purposes. Moreover, because a portion of such holder’s gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to “unrealized receivables,” including depreciation recapture” or to substantially appreciated inventory items owned by MEP and its subsidiaries, a holder of Class A Common Units may recognize both ordinary income and a capital loss as a result of the Merger.

Benefits and Detriments to MEP and the Enbridge Parties

The primary benefits of the Merger to MEP and the Enbridge Parties include the following:

 

    Increased flexibility as EECI and EEP position the gas gathering and processing business to be a sustainable, long-term business.

 

    If MEP successfully executes its business strategy, the value of the Enbridge Parties’ equity investment could increase because of possible increases in future revenues and cash flow, increases in underlying value of MEP or the payment of distributions, if any, that would accrue to the Enbridge Parties.

 

    The Enbridge Parties (other than Merger Sub), as the owners of MEP, will become the beneficiaries of the savings associated with the reduced burden of complying with the substantive requirements that federal securities laws, including the Sarbanes-Oxley Act of 2002, impose on public companies.

The primary detriments of the Merger to MEP and the Enbridge Parties include the following:

 

    The Merger is being undertaken during a time of low commodity prices, and all of the risk of any possible decrease in the revenues and cash flow, growth or value of MEP following the Merger will be borne by the Enbridge Parties (other than Merger Sub).

 

    Following the Merger, there will be no trading market for the equity securities of MEP, as the surviving entity.

 

 

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    The potential benefits sought in the Merger may not be realized.

 

    If EEP seeks to sell MEP in the future, the valuation of MEP at that time could be less than the current valuation.

Interests of Certain Persons in the Merger

In considering the recommendations of the MEP GP Board and the MEP Committee with respect to the Merger, the MEP Unaffiliated Unitholders should be aware that certain of the executive officers and directors of MEP GP have interests in the transaction that differ from, or are in addition to, the interests of the MEP Unaffiliated Unitholders generally, including:

 

    certain executive officers of MEP GP hold unvested performance share units in MEP;

 

    certain directors and executive officers of MEP GP, some of whom are also directors and/or officers of EECI, own Class A Common Units that will be cancelled at the Effective Time of the Merger and converted into the right to receive the Merger Consideration;

 

    the chairman of the MEP Committee will receive $5,000 for his service as chairman of the MEP Committee and each member of the MEP Committee will receive a fee of $1,500 per meeting;

 

    each Member of the MEP Committee will receive a reasonable hourly fee for time spent in connection with litigation arising out of their service on the MEP Committee, in addition to any other compensation they receive for service on the MEP GP Board and its committees; and

 

    all of the directors and executive officers of MEP GP will receive continued indemnification for their actions as directors and executive officers after the Effective Time of the Merger. However, the Merger will not trigger any “change of control” provision in the employment contract of any of the directors or executive officers of MEP GP.

In addition, in 2015 and 2016, each of MEP GP’s executive officers was granted MEP PSUs. When granted, the MEP PSUs represented the right to receive, for each PSU earned, a cash payment upon vesting of the award based on the then current fair market value of one MEP common unit. The MEP PSUs generally vest over a three year performance period and could be earned at a level ranging from 0% to 200% based on attainment of performance metrics that were tied to MEP’s cash flow and relative yield for the applicable performance period. The following table sets forth as of February 13, 2017, the number of MEP PSUs held by each of MEP GP’s named executive officers with respect to such awards granted in each of 2015 and 2016:

 

Name of Executive Officer

   2015 MEP PSUs
(the “2015 PSUs”)
   2016 MEP PSUs
(the “2016 PSUs”)

C. Gregory Harper

   31,973    67,065

Stephen J. Neyland

   13,897    20,776

R. Poe Reed

   21,357    37,569

E. Chris Kaitson

   10,685    15,978

Kerry C. Puckett

   14,496    21,677

In connection with the Merger, EECI and MEP GP have determined that the 2015 PSUs will be deemed earned at a level of 25% and that the 2016 PSUs will be deemed earned at a level of 125%. The corresponding payout (i.e., $8.00 per earned PSU) will be paid upon vesting of the awards in 2018 and 2019, respectively, generally subject to continued employment through the end of the vesting period and subject to proration in the event of certain terminations. The payout amount will also be adjusted to reflect Enbridge Inc.’s total shareholder return over the remainder of the vesting period (i.e., increased or decreased by an amount that corresponds to the gain or loss that would have occurred if the payout amount were invested in Enbridge Inc.’s common shares on the closing date of the Merger).

 

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Golden Parachute Compensation

The information set forth below is required by Item 402(t) of Regulation S-K regarding compensation that is based on or otherwise relates to the Merger which the current MEP GP named executive officers could receive in connection with the Merger.

 

Name

   Cash (1)    Total

C. Gregory Harper

   $734,596    $734,596

Stephen J. Neyland

   $235,554    $235,554

R. Poe Reed

   $418,404    $418,404

E. Chris Kaitson

   $181,150    $181,150

Kerry C. Puckett

   $245,762    $245,762

 

(1) Amount shown represents the cash payout to which the named executive officer may become entitled in respect of his or her MEP PSUs, assuming the Merger closed on February 13, 2017. Such amount will be adjusted to account for the earnings or losses that would occur if the amount was deemed invested in Enbridge Inc.’s common shares on the closing date of the Merger through the vesting date of the applicable award, as described above.

Material U.S. Federal Income Tax Considerations

The receipt of cash in exchange for Class A Common Units pursuant to the Merger will be a taxable transaction for U.S. federal income tax purposes to holders. A holder who receives cash in exchange for Class A Common Units pursuant to the Merger will recognize gain or loss in an amount equal to the difference between:

 

    the sum of (1) the amount of any cash received and (2) such holder’s share of MEP’s nonrecourse liabilities immediately prior to the Merger; and

 

    such holder’s adjusted tax basis in the Class A Common Units exchanged therefor (which includes such holder’s share of MEP’s nonrecourse liabilities immediately prior to the Merger).

Gain or loss recognized by a holder will generally be taxable as capital gain or loss. However, a portion of this gain or loss, which could be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to “unrealized receivables, ” including depreciation recapture, or to substantially appreciated “inventory items” owned by MEP and its subsidiaries. Passive losses that were not deductible by a holder in prior taxable periods because they exceeded such holder’s share of MEP’s income may become available to offset a portion of the gain recognized by such holder.

The U.S. federal income tax consequences of the Merger to a holder of Class A Common Units will depend on such unitholder’s own personal tax situation. Accordingly, we strongly urge you to consult your tax advisor for a full understanding of the particular tax consequences of the Merger to you.

Please read “Material U.S. Federal Income Tax Considerations” for a more complete discussion of certain U.S. federal income tax consequences of the Merger.

Financing of the Merger

The total amount of funds necessary to consummate the Merger and the related transactions is anticipated to be approximately $170,200,000. EECI expects to fund the Merger through an intercompany financing from a wholly owned direct or indirect subsidiary of Enbridge.

Estimated Fees and Expenses

Under the terms of the Merger Agreement, all expenses will generally be borne by the party incurring such expenses except that EECI and MEP will each pay one half of the expenses, other than the expenses of financial

 

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advisors or outside legal advisors, incurred in connection with the preparation, printing, filing and mailing of this information statement and the Schedule 13E-3 and any amendments or supplements thereto.

Evercore has provided certain financial advisory services to the MEP Committee in connection with the Merger. MEP has agreed to pay $2.0 million to Evercore as compensation for its services, and MEP has agreed to reimburse Evercore for all reasonable out-of-pocket expenses incurred by them, including the reasonable fees and expenses of legal counsel, and to indemnify Evercore against certain liabilities and expenses in connection with its engagement, including certain liabilities under the federal securities laws. See “—Opinion of Evercore Group L.L.C. – Financial Advisor to the MEP Committee” for more information about Evercore’s compensation.

The following is an estimate of fees and expenses to be incurred and paid by MEP in connection with the Merger:

 

Description

   Amount  

Legal

   $ 600,000  

Financial Advisors

   $ 2,000,000  

Printing and Mailing

   $ 40,000  

SEC Filing Fees

   $ 19,726  

Paying Agent

   $ 15,000  

Miscellaneous

   $ —    
  

 

 

 

Total

   $ 2,674,726  
  

 

 

 

Enbridge and its affiliates (other than MEP) are expected to incur and pay fees and expenses of approximately $4,385,000 in connection with the Merger, consisting primarily of legal and financial advisory fees.

Regulatory Approvals Required for the Merger

Neither MEP nor any of the Enbridge Parties is aware of any federal or state regulatory approval required in connection with the Merger, other than compliance with relevant federal securities laws.

Certain Legal Matters

General

In the Merger Agreement, the parties have agreed to cooperate with each other to make all filings with governmental authorities and to obtain all governmental approvals and consents necessary to consummate the Merger, subject to certain exceptions and limitations. It is a condition to the consummation of the Merger that required governmental consents and approvals have been obtained before the effective date of the Merger.

Certain Litigation

Currently, MEP is not aware of any pending litigation related to the Merger.

Provisions for Unaffiliated Security Holders

Except as provided for in the Merger Agreement, no provision has been made to grant MEP Unaffiliated Unitholders access to the partnership files of MEP, MEP GP or the Enbridge Parties or to obtain counsel or appraisal services at the expense of the foregoing parties.

No Appraisal Rights

Holders of Class A Common Units are not entitled to dissenters’ rights of appraisal under the MEP Partnership Agreement, the Merger Agreement or applicable Delaware law. The foregoing discussion is not a

 

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complete statement of law pertaining to appraisal rights under Delaware law and is qualified in its entirety by references to Delaware law, other applicable law, the MEP Partnership Agreement and the Merger Agreement.

Accounting Treatment of the Merger

The Merger will be accounted for in accordance with GAAP. As EECI, through its direct and indirect interest through EEP, will have a controlling financial interest in MEP, both before and after the Merger, changes in its ownership interest in MEP will be accounted for as an equity transaction and no gain or loss on the Merger will be recognized in its consolidated statements of earnings.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This information statement and the other documents referred to or incorporated by reference into this information statement contain or may contain “forward-looking statements.”

Statements included in or incorporated by reference into this information statement that are not historical facts, including statements about the beliefs and expectations of the MEP GP Board or the management of MEP, are forward-looking statements. Words such as “anticipate,” “believe,” “continue,” “consider,” “could,” “estimate,” “evaluate,” “expect,” “explore,” “forecast,” “intend,” “may,” “opportunity,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words are intended to identify forward-looking statements but are not the exclusive means of identifying such statements. All forward-looking statements speak only as of the date of this information statement or the date of such other filing, as the case may be, and we undertake no obligation to publicly update any forward-looking statement. Although MEP believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved and such statements are subject to various risks and uncertainties. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecasted in such statements and readers are cautioned not to place undue reliance on such statements. MEP’s business may be influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond MEP’s control. These factors include, but are not limited to, the occurrence of any event, change or other circumstance that could give rise to termination of the Merger Agreement; the inability to complete the Merger due to the failure to obtain the unitholder approvals for the Merger or the failure to satisfy other conditions to completion of the Merger, including that a governmental entity may prohibit, delay or refuse to grant approval for the consummation of the Merger; risks related to disruption of management’s attention from MEP’s ongoing business operations due to the Merger; the impact of the announcement of the proposed Merger on relationships with third parties, including commercial counterparties, employees and competitors, and risks associated with the loss and ongoing replacement of key personnel; risks relating to unanticipated costs of integration in connection with the proposed Merger, including operating costs, customer loss or business disruption being greater than expected; changes in general economic conditions; actions taken by third-party operators, processors and transporters; the demand for natural gas storage and transportation services; MEP’s ability to successfully implement its business plan; MEP’s ability to complete internal growth and expansion projects on time and on budget; changes in the demand for, the supply of, forecast data for, and price trends related to natural gas, NGLs and crude oil, and the response by natural gas and crude oil producers to any of these factors; the effects of competition, in particular, by other pipeline and gathering systems, as well as other processing and treating plants; shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to which we sell products; operating hazards and other risks that may not be fully covered by insurance; changes in or challenges to our rates; changes in laws or regulation to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; cost overruns and delays on construction projects resulting from numerous factors; our ability to comply with covenants in our debt agreements; the results of our and EEP’s reviews of strategic alternatives; changes in MEP’s treatment as a partnership for U.S. federal or state income tax purposes; the effects of existing and future laws and governmental regulations; and the effects of future litigation, including litigation relating to the Merger.

MEP cautions that the foregoing list of factors is not exhaustive. Other unknown or unpredictable factors could also have material adverse effects on MEP’s performance or achievements prior to the Merger. Discussions of some of these other important factors and assumptions can be found in MEP’s Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 2015, as amended, and MEP’s other filings with the SEC, which are available at http://www.sec.gov. All forward-looking statements included in this information statement are expressly qualified in their entirety by such cautionary statements. MEP expressly disclaims any obligation to update, amend or clarify any forward-looking statement to reflect events, new information or circumstances occurring after the date of this information statement except as required by applicable law.

 

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The forward-looking statements contained in this information statement, including forward-looking statements included in annexes attached to this information statement, made in connection with the transactions contemplated by the Merger Agreement are excluded from the safe harbor protection provided by the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933, as amended.

 

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OTHER MATTERS

Householding of Materials

Some banks, brokers and other nominees may be participating in the practice of “householding” information statements and annual reports. This means that only one copy of this notice and information statement may have been sent to multiple unitholders in your household. If you would prefer to receive separate copies of the information statement either now or in the future, please contact your bank, broker or other nominee. Upon written or oral request to MEP, MEP will provide a separate copy of the information statement. In addition, MEP Common Unitholders sharing an address can request delivery of a single copy of the information statement if you are receiving multiple copies upon written or oral request to MEP at the address and telephone number stated above.

 

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THE MERGER AGREEMENT

The following describes the material provisions of the Merger Agreement, which is attached as Annex A and incorporated by reference herein. The description in this section and elsewhere in this information statement is qualified in its entirety by reference to the Merger Agreement. This summary does not purport to be complete and may not contain all of the information about the Merger Agreement that is important to you. MEP encourages you to read the Merger Agreement carefully and in its entirety before making any decisions regarding the Merger, as it is the legal document governing the Merger. The Merger Agreement and this summary of its terms have been included to provide you with information regarding the terms of the Merger Agreement.

Factual disclosures about MEP or EECI or any of their respective subsidiaries or affiliates contained in this information statement or their respective public reports filed with the SEC may supplement, update or modify the factual disclosures about MEP or EECI or their respective subsidiaries or affiliates contained in the Merger Agreement and described in these summaries. The representations, warranties and covenants made in the Merger Agreement by MEP or EECI, as applicable, were qualified and subject to important limitations agreed to by MEP and EECI, respectively, in connection with negotiating the terms of the Merger Agreement. In particular, in your review of the representations and warranties contained in the Merger Agreement and described in this summary, it is important to bear in mind that the representations and warranties were negotiated with the principal purpose of allocating risk between the parties to the Merger Agreement, rather than establishing matters as facts. The representations and warranties may also be subject to a contractual standard of materiality different from those generally applicable to stockholders or unitholders and reports and documents filed with the SEC and in some cases were qualified by confidential disclosures that were made by each party to the other, which disclosures are not reflected in the Merger Agreement or otherwise publicly disclosed. For the foregoing reasons, the representations, warranties and covenants or any descriptions of those provisions should not be read alone.

Unless otherwise expressly stated, for the purposes of the Merger Agreement, references to an affiliate or subsidiary of EECI do not include MEP, MEP GP or their subsidiaries.

The Merger

Pursuant to the Merger Agreement, Merger Sub, a wholly owned subsidiary of EECI, will merge with and into MEP, with MEP surviving the Merger and continuing to exist as a Delaware limited partnership, and each Class A Common Unit issued and outstanding immediately prior to the Effective Time and owned by MEP Unaffiliated Unitholders will be converted into the right to receive (1) $8.00 in cash, without interest. Following the consummation of the Merger, EECI will own approximately 48% of the limited partner interests in MEP, and EEP will own the remaining approximate 52% of the limited partner interests and 2% general partner interest in MEP.

The limited liability company interests in Merger Sub issued and outstanding immediately prior to the Effective Time will be converted automatically into the number of Class A Common Units of the surviving entity equal to the Class A Common Units converted into the right to receive the Merger Consideration. At the Effective Time, the books and records of MEP will be revised to reflect that all limited partners of MEP immediately prior to the Effective Time whose Class A Common Units are converted into the right to receive the Merger Consideration cease to be limited partners of MEP and that, immediately following the Effective Time, EECI and EEP will be the only limited partners of the surviving entity.

Effective Time; Closing

The Effective Time will occur at such time as MEP and EECI cause a certificate of merger to be duly filed with the Secretary of State of the State of Delaware or at such later date or time as may be agreed by MEP and EECI in writing and specified in the certificate of merger.

 

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The closing of the Merger will take place on the third business day after the satisfaction or waiver of the conditions set forth in the Merger Agreement (other than conditions that by their nature are to be satisfied at the closing but subject to the satisfaction or waiver of those conditions), or at such other date as MEP and EECI may agree.

Conditions to Completion of the Merger

MEP and EECI may not complete the Merger unless each of the following conditions is satisfied or waived:

 

    MEP has obtained the Partnership Unitholder Approval; and

 

    the absence of any legal restraint or prohibition enjoining or otherwise prohibiting the consummation of the Merger or making the consummation of the Merger Transactions illegal.

The obligations of EECI and Merger Sub to effect the Merger are subject to the satisfaction or waiver of the following additional conditions:

 

    the representations and warranties in the Merger Agreement of MEP and MEP GP qualified as to materiality are true and correct in all respects, and those not so qualified shall be true and correct in all material respects, as of the closing date, as if made at and as of such time (except to the extent expressly made as of an earlier date, in which case as of such earlier date);

 

    MEP and MEP GP having performed in all material respects all covenants and obligations required to be performed by each of them under the Merger Agreement; and

 

    the receipt by EECI of an officer’s certificate signed on behalf of MEP and MEP GP by an executive officer of MEP GP certifying that the two preceding conditions have been satisfied.

The obligation of EECI to effect the Merger is subject to the satisfaction or waiver of the following additional conditions:

 

    the representations and warranties in the Merger Agreement of EECI and Merger Sub qualified as to materiality are true and correct in all respects, and those not so qualified shall be true and correct in all material respects, as of the closing date, as if made at and as of such time (except to the extent expressly made as of an earlier date, in which case as of such earlier date);

 

    EECI and Merger Sub having performed in all material respects all covenants and obligations required to be performed by each of them under the Merger Agreement; and

 

    the receipt by MEP of an officer’s certificate signed on behalf of EECI by an executive officer of EECI certifying that the two preceding conditions have been satisfied.

MEP GP Recommendation and MEP GP Adverse Recommendation Change

The MEP Committee unanimously (1) determined that the Merger Agreement, the Support Agreement and the Merger Transactions are fair and reasonable to and in the best interests of MEP and its subsidiaries and the MEP Unaffiliated Unitholders, (2) approved the Merger Agreement, the Support Agreement and the Merger Transactions, (3) recommended that the MEP GP Board approve the Merger Agreement and the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement and the consummation of the Merger Transactions, and (4) recommended that the MEP GP Board submit the Merger Agreement to a vote of MEP’s limited partners and recommend the approval of the Merger Agreement by MEP’s limited partners. For more information regarding the recommendation of the MEP Committee and the MEP GP Board, including the obligations of the MEP Committee and the MEP GP Board in making such determination under the MEP partnership agreement, see “Special Factors—Recommendation of the MEP Committee and the MEP GP Board; Reasons for Recommending Approval of the Merger Agreement and the Merger Transactions.”

The MEP GP Board (acting based in part upon the recommendation of the MEP Committee and after receiving the approval of the MEP GP’s sole member) unanimously (1) determined that each of the Merger

 

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Agreement, the Support Agreement and the Merger Transactions is fair and reasonable to and in the best interests of MEP and its subsidiaries and MEP’s limited partners, (2) approved the Merger Agreement, the Support Agreement, the execution, delivery and performance of the Merger Agreement and the Support Agreement and the consummation of the Merger Transactions, (3) resolved to submit the Merger Agreement to a vote of MEP’s limited partners by written consent and (4) recommended approval of the Merger Agreement, including the Merger, by MEP’s limited partners.

The Merger Agreement provides that MEP and MEP GP will not, and will cause their respective subsidiaries and their respective directors, officers, employees, investment bankers, financial advisors, attorneys, accountants, agents and other representatives not to, directly or indirectly:

 

    withdraw, modify or qualify, or propose publicly to withdraw, modify or qualify, in a manner adverse to EECI, the recommendation of MEP (through the MEP GP Board’s recommendation) or publicly recommend the approval or adoption of, or publicly approve or adopt, or propose to publicly recommend, approve or adopt, any Acquisition Proposal (as defined in the Merger Agreement), or fail to recommend against acceptance of any tender offer or exchange offer for Class A Common Units within ten (10) business days after commencement of such offer, or resolve or agree to take any of the foregoing actions; or

 

    fail to include the recommendation of MEP (through the MEP GP Board’s recommendation) that MEP’s limited partners approve the Merger Agreement in this information statement.

MEP, MEP GP and any of their subsidiaries taking any of the actions described above is referred to as a “MEP GP Adverse Recommendation Change.”

Subject to the conditions described below, the MEP GP Board, after consulting with the MEP Committee may, at any time prior to obtaining the Partnership Unitholder Approval, make a MEP GP Adverse Recommendation Change if the MEP GP Board determines in good faith (after consultation with its financial advisor and outside legal counsel and the MEP Committee) (1) that an Acquisition Proposal constitutes a Superior Proposal (as defined in the Merger Agreement) and (2) that the failure to take such action would be materially adverse to the interests of the MEP Unaffiliated Unitholders or otherwise inconsistent with the GP Board’s duties under the MEP Partnership Agreement and applicable law. The MEP Committee may not effect a MEP GP Adverse Recommendation Change in this manner unless (1) the MEP GP Board has provided prior written notice to EECI specifying in reasonable detail the reasons for such action at least five days in advance of its intention to take such action, unless at the time such notice is otherwise required there are fewer than five days prior to the expected date of the Partnership Unitholder Approval, in which case the such notice shall be provided as far in advance as practicable, (2) if applicable, EECI has been provided all materials and information delivered or made available to the person or group of persons making any Superior Proposal in connection with such Superior Proposal (to the extent not previously provided) and (3) during this period, the MEP GP Board has negotiated, and has used its reasonable best efforts to cause its financial advisors and outside legal counsel to negotiate, with EECI in good faith (to the extent EECI desires to negotiate in its sole discretion) to make such adjustments in the terms of the Merger Agreement so that the failure to effect such MEP GP Adverse Recommendation Change would not be adverse to the interests of the MEP Unaffiliated Unitholders or otherwise inconsistent with the MEP GP Board’s duties under the MEP Partnership Agreement and applicable law, provided that the MEP GP Board or MEP Committee, as applicable, must take into account all changes to the terms of the Merger Agreement proposed by EECI in determining whether to make, or in the case of the MEP Committee, recommend, a MEP GP Adverse Recommendation Change.

MEP Unitholder Approval

Under the applicable provisions of the MEP Partnership Agreement, the approval of the Merger Agreement requires the approval of at least a majority of the outstanding common units. As of February 15, 2017, EEP owns approximately 52% of MEP’s outstanding common units. As a result, EEP owns a sufficient number of common

 

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units to approve the Merger Agreement and the Merger Transactions on behalf of the holders of MEP common units. Concurrently with the execution of the Merger Agreement, MEP has entered into the Support Agreement with EECI and EEP whereby EEP has agreed, in its capacity as a unitholder of MEP, to vote its units in favor of the Merger Agreement and the Merger Transactions.

The Merger Agreement requires MEP, through the MEP GP Board, to recommend to MEP’s limited partners approval of the Merger Agreement. MEP’s obligation to submit the Merger Agreement to MEP’s limited partners for approval is not affected by a MEP Adverse Recommendation Change.

The Merger Consideration

At the Effective Time, each Class A Common Unit issued and outstanding as of immediately prior to the Effective Time and owned by a MEP Unaffiliated Unitholder will be converted into the right to receive $8.00 in cash, without interest. As of the Effective Time, all Class A Common Units converted into the right to receive the Merger Consideration will no longer be outstanding and will automatically be cancelled and cease to exist. The general partner interest, the Class A Common Units owned by EEP and the incentive distribution rights issued and outstanding as of immediately prior to the Effective Time will be unaffected by the Merger and will remain outstanding and no consideration will be delivered in respect of such partnership interests.

Treatment of Long-Term Incentive Plan

The Merger Agreement provides that prior to the Effective Time, EECI and MEP GP will determine the terms and conditions of any adjustments, settlements or substitutions to be made to or with respect to outstanding awards under the MEP Long-Term Incentive Plan in connection with the Merger (each a “Partnership Incentive Plan Adjustment”), which Partnership Incentive Plan Adjustments, if any shall comply with the terms of the MEP Long-Term Incentive Plan or any award agreement thereunder and shall become effective as of the Effective Time. EECI and MEP GP have determined to freeze all MEP PSU performance metrics, and the cash payment due upon vesting on the original maturity date will be based on the $8.00 per unit merger consideration with a potential additional amount that will fluctuate based on Enbridge’s total shareholder return corresponding to an investment in Embridge over the remainder of the applicable vesting period. For additional information about these awards and the adjustments thereto, please see “Special Factors—Interests of Certain Persons in the Merger.”

As soon as practicable following the Effective Time, MEP will file a post-effective amendment to the Form S-8 registration statement filed by MEP on August 15, 2014 and deregister all Class A Common Units registered on that registration statement.

Distributions

To the extent applicable, holders of Class A Common Units immediately prior to the Effective Time will have continued rights to any distribution, without interest, with respect to such Class A Common Units with a record date occurring prior to the Effective Time that has been declared by MEP GP or made by MEP with respect to such Class A Common Units in accordance with the terms of the Merger Agreement and which remains unpaid as of the Effective Time. Such distributions by MEP are not part of the Merger Consideration and will be paid on the payment date set therefor to such holders of Class A Common Units, as applicable. To the extent applicable, holders of Class A Common Units prior to the Effective Time will have no rights to any distribution with respect to such Class A Common Units with a record date occurring on or after the Effective Time that may have been declared by MEP GP or made by MEP with respect to such Class A Common Units prior to the Effective Time and which remains unpaid as of the Effective Time.

Until the Effective Time, EECI was required pursuant to the merger agreement, subject to compliance with applicable law, to cause MEP GP to declare, and MEP to pay, regular quarterly cash distributions to holders of

 

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Class A Common Units with respect to the quarter ended December 31, 2016 in accordance with the MEP Partnership Agreement (the “Fourth Quarter Distribution”); provided, however, that subject to applicable laws, the Fourth Quarter Distribution could not be less than $0.3575 without the prior approval of the MEP Committee. On February 14, 2017, MEP paid the Fourth Quarter Distribution in an amount equal to $0.3575 per unit on all of its outstanding common and subordinated units.

Surrender of Class A Common Units

Before the closing of the Merger Agreement, EECI will appoint a paying agent reasonably acceptable to MEP for the purpose of exchanging the Class A Common Units, whether represented by certificates or in book-entry form only, for the Merger Consideration. As promptly as practicable after the Effective Time, EECI will send, or will cause the paying agent to send, to each record holder of Class A Common Units as of the Effective Time (as defined pursuant to the Merger Agreement) whose Class A Common Units were converted into the right to receive the Merger Consideration, a letter of transmittal in a form as MEP and EECI may reasonably agree, including instructions for use in effecting the surrender the Class A Common Units.

On or before the closing date, EECI will deposit with the paying agent in trust for the benefit of the holders of Class A Common Units as of the Effective Time which were converted into the right to receive the Merger Consideration, an amount of cash equal to the amount of the aggregate Merger Consideration payable pursuant to the Merger Agreement. We refer to such cash deposited with the paying agent as the “Exchange Fund.” The paying agent will deliver the Merger Consideration contemplated to be paid pursuant to the Merger Agreement out of the Exchange Fund. Each holder of Class A Common Units that have been converted into the right to receive the Merger Consideration, upon delivery to the paying agent of a properly completed letter of transmittal and surrender of such Class A Common Units, will be entitled to receive a check in an amount equal to the aggregate amount of cash that such holder has a right to receive under the Merger Agreement.

Adjustments to Prevent Dilution

The Merger Consideration will be appropriately adjusted to reflect fully the effect of any unit dividend, subdivision, reclassification, recapitalization, split, split-up, unit distribution, combination, exchange of units or similar transaction with respect to the number of outstanding Class A Common Units prior to the Effective Time to provide the holders of Class A Common Units the same economic effect as contemplated by the Merger Agreement prior to such event.

Withholding

EECI, Merger Sub, the surviving entity and the paying agent retained by EECI for the purpose of exchanging Class A Common Units for the Merger Consideration will be entitled to deduct and withhold from the consideration otherwise payable pursuant to the Merger Agreement such amounts, if any, as are required to be deducted and withheld with respect to the making of such payment under applicable tax law. To the extent amounts are so withheld, such withheld amounts will be treated as having been paid to the former holder of Class A Common Units in respect of whom such withholding was made.

Filings

Pursuant to the Merger Agreement, EECI, on the one hand, and MEP and MEP GP, on the other hand, have agreed to cooperate and use, and to cause their respective subsidiaries to use their respective commercially reasonable efforts to (1) take, or cause to be taken, all actions, and do, or cause to be done, all things, necessary, proper or advisable to cause the conditions to the closing of the Merger Agreement to be satisfied as promptly as practicable (and in no event later than the Outside Date), and to consummate and make effective, in the most expeditious manner practicable, the transactions contemplated by the Merger Agreement, including to prepare

 

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and file as promptly as practicable all documentation to effect all necessary filings, notifications, notices, petitions, statements, registrations, submissions of information, applications and other documents (including any required or recommended filings under applicable antitrust laws), (2) obtain promptly (and in any event no later than the Outside Date) all approvals, consents, clearances, expirations or terminations of waiting periods, registrations, permits, authorizations and other confirmations from any governmental authority or third party necessary, proper or advisable to consummate the transactions contemplated by the Merger Agreement and (3) defend legal proceedings challenging the Merger Agreement or the consummation of the transactions contemplated thereby.

Termination

EECI and MEP may terminate the Merger Agreement at any time prior to the Effective Time by mutual written consent authorized by the EECI Board and MEP GP Board, after consulting with the MEP Committee.

In addition, either EECI or MEP (duly authorized by the MEP GP Board after consulting with the MEP Committee) may terminate the Merger Agreement at any time prior to the Effective Time by written notice to the other party if:

 

    the closing of the Merger has not occurred on or before the Outside Date, except that the right to terminate will not be available (1) to MEP, if the failure to satisfy such condition was due to the failure of MEP or MEP GP to perform and comply in all material respects with the covenants and agreements contained in the Merger Agreement to be performed or complied with it prior to the closing of the Merger, (2) EECI, if the failure to satisfy such condition was due to the failure of EECI, Merger Sub or EEP to perform and comply in all material respects with the covenants and agreements contained in the Merger Agreement or the Support Agreement, as applicable, to be performed or complied with by it prior to the closing of the Merger, or (3) MEP or EECI if, in the case of EECI, MEP or MEP GP and in the case of MEP, EECI or Merger Sub, has filed (and is then pursuing) an action seeking specific performance of the obligations of the other party as permitted by the Merger Agreement;

 

    any restraint is in effect and has become final and nonappealable that has the effect of enjoining, restraining, preventing or prohibiting the consummation of the transactions contemplated by the Merger Agreement or making the consummation of the transactions contemplated by the Merger Agreement illegal, except that the right to terminate will not be available to EECI or MEP if such restraint is due to the failure, in the case of MEP, MEP or MEP GP and in the case of EECI, EECI, Merger Sub or EEP, to perform in all material respects its obligations under the Merger Agreement or the Support Agreement, as applicable; or

 

    obtained MEP Adverse Recommendation Change occurs.

EECI also may terminate the Merger Agreement if:

 

    prior to obtaining the Partnership Unitholder Approval, if MEP is in willful breach of its obligations pursuant to the Merger Agreement, except that EECI shall not have the right to terminate the Merger Agreement if EECI, Merger Sub or EEP is then in material breach of any of its representations, warranties, covenants or agreements contained in the Merger Agreement or the Support Agreement, as applicable; or

 

    MEP or MEP GP breaches or fails to perform any of its representations, warranties, covenants or agreements such that certain closing conditions would not be satisfied, or if such breach or failure is capable of being cured, such breach or failure has not been cured within the earlier of (x) 30 days following delivery of written notice by EECI or (y) the Outside Date and EECI is not then in material breach of any of its representations, warranties, covenants or agreements contained in the Merger Agreement or the Support Agreement, as applicable.

MEP (duly authorized by the MEP GP Board after consulting with the MEP Committee) also may terminate the Merger Agreement if EECI or Merger Sub breaches or fails to perform any of its representations, warranties,

 

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covenants or agreements such that certain closing conditions would not be satisfied, or if such breach or failure is capable of being cured, such breach or failure has not been cured within the earlier of (x) 30 days following delivery of written notice by MEP or (y) the Outside Date and neither of MEP or MEP GP is then in material breach of any of its representations, warranties, covenants or agreements contained in the Merger Agreement.

Effect of Termination; Remedies

In the event of termination of the Merger Agreement as summarized above under “—Termination,” the Merger Agreement will terminate, except for certain provisions, and there will be no liability on the part of any of EECI, Merger Sub or MEP and MEP GP or their respective directors, officers and affiliates to the other parties except for any failure to consummate the Merger and the Merger Transactions when required pursuant to the Merger Agreement. In the event of a party’s intentional and material breach of the Merger Agreement or intentional fraud, then the other applicable party or parties will be entitled to pursue any and all legally available remedies, including equitable relief, and to seek recovery of all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees and time value of money). For the avoidance of doubt, there will be no liability on the part of the MEP GP or MEP or their respective directors, officers and affiliates if the Merger Agreement is terminated by EECI or MEP due to a MEP Adverse Recommendation Change. Notwithstanding the foregoing, in no event will MEP GP or MEP or their respective directors, officers and affiliates have any liability for any matter set forth in the second sentence of this paragraph for any action taken or omitted to be taken by MEP GP, MEP, any of their respective subsidiaries or any of their respective representatives at the direction of EECI, any of its subsidiaries or any of their respective representatives.

Conduct of Business Pending the Merger

Subject to certain exceptions, unless EECI consents in writing (which consent must not be unreasonably withheld, delayed or conditioned), MEP GP and MEP have agreed not to, and will cause each of their respective subsidiaries not to, and EECI has agreed not to cause MEP or MEP GP to:

 

    conduct its business and the business of its subsidiaries other than in the ordinary course or fail to use commercially reasonable efforts to preserve intact its business organization, goodwill and assets and maintain its rights, franchises and existing relations with customers, suppliers, employees and business associates, except in the case of action that could have a material adverse effect as defined in the Merger Agreement;

 

    other than the New Class A Common Units and annual compensatory equity awards granted to non-employee directors of the MEP GP Board in the ordinary course, (1) issue, sell or otherwise permit to become outstanding, or authorize the creation of, any additional equity securities (other than pursuant to the existing terms of any Rights outstanding as of the date of the Merger Agreement, as defined in the Merger Agreement) or any additional rights, (2) enter into any agreement with respect to the foregoing, in each case that would materially adversely affect its ability to consummate the transactions contemplated by the Merger Agreement or (3) except as expressly contemplated by the Merger Agreement, issue, grant or amend any award under the Partnership Long-Term Incentive Plan;

 

    (1) split, combine or reclassify any of its equity interests or authorize or propose the issuance of any other securities in respect of, in lieu of or in substitution for its equity interests or (2) repurchase, redeem or otherwise acquire (or permit any of its subsidiaries to purchase, redeem or otherwise acquire) any equity interests or rights in MEP, except as required by the terms of its securities outstanding on the date of the Merger Agreement by the Partnership Long-Term Incentive Plan;

 

    (1) sell, lease or dispose of any portion of its assets, business or properties other than in the ordinary course of business, (2) acquire, by merger or otherwise, or lease any assets or any business or property of any other entity other than in the ordinary course of business consistent with past practice or (3) convert from a limited partnership or limited liability company, as the case may be, to any other business entity;

 

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    declare or pay dividends or distributions to the holders of any Units or equity interests in MEP, other than as described in “—Distributions”;

 

    amend the MEP Partnership Agreement, as in effect on the date of the Merger Agreement;

 

    enter into any material contract, except as would not have a material adverse effect on MEP and would not be materially adverse to EECI, Merger Sub and their respective subsidiaries, taken as a whole;

 

    modify, amend, terminate, assign or waive any rights under any material contract in a manner which is materially adverse to EECI, Merger Sub and their respective subsidiaries, taken as a whole, or which would have a material adverse effect on MEP;

 

    waive, release, assign, settle or compromise any legal proceeding, including any state or federal regulatory proceeding, seeking damages or injunction or other equitable relief that is material to MEP and its subsidiaries taken as a whole or is a claim, action or proceeding relating to the transactions contemplated by the Merger Agreement;

 

    implement or adopt any material change in accounting principles, practices or methods, other than as required by GAAP or other applicable regulatory authorities;

 

    (1) change its fiscal year or any method of tax accounting, (2) make, change or revoke any material tax election, (3) settle or compromise any material liability for taxes, (4) file any material amended tax return or (5) take any action or fail to take any action that would reasonably be expected to cause MEP or any of its subsidiaries to be treated, for U.S. federal income tax purposes, as a corporation;

 

    other than in the ordinary course of business consistent with past practice, (1) incur, assume, guarantee or otherwise become liable for any indebtedness (directly, contingently or otherwise), other than borrowings under existing revolving credit facilities or intercompany money pool arrangements or (2) create any lien on its property or the property of its subsidiaries to secure indebtedness;

 

    authorize, recommend, propose or announce an intention to adopt a plan of complete or partial dissolution or liquidation;

 

    knowingly take any action that is intended to or is reasonably likely to result in (1) any of its representations and warranties contained in the Merger Agreement being or becoming untrue in any material respect at the closing date, (2) any of the conditions to the closing of the Merger as set forth in the Merger Agreement not being satisfied, (3) any material delay in or prevention of the consummation of the Merger or (4) a material violation of any provision of the Merger Agreement; or

 

    agree or commit to do anything described above.

Indemnification; Directors’ and Officers’ Insurance

From and after the Effective Time, MEP GP and MEP (as the surviving entity of the Merger) jointly and severally agree to indemnify, defend and hold harmless against any cost or expenses (including attorneys’ fees), judgments, settlements, fines and other sanctions, losses, claims, damages or liabilities and amounts paid in settlement in connection with any actual or threatened legal proceeding, and provide advancement of expenses with respect to each of the foregoing, to any person who is now, or has been or becomes at any time prior to the Effective Time, an officer, director or employee of MEP or any of its subsidiaries or MEP GP, to the fullest extent permitted under applicable law. In addition, MEP GP and MEP (as the surviving entity of the Merger) will honor the provisions regarding elimination of liability of officers and directors, indemnification of officers, directors and employees and advancement of expenses contained in the organizational documents of MEP and MEP GP immediately prior to the Effective Time and ensure that the organizational documents of MEP and MEP GP or any of their respective successors or assigns, if applicable, will contain provisions no less favorable, for a period of six years following the Effective Time, with respect to indemnification, advancement of expenses and exculpation of present and former directors, officers, employees and agents of MEP and MEP GP than are presently set forth in such organizational documents. In addition, MEP will maintain in effect for six years from the Effective Time,

 

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MEP’s current directors’ and officers’ liability insurance policies covering acts or omissions occurring at or prior to the Effective Time with respect to such indemnified persons, provided that in no event will MEP be required to expend more than an amount per year equal to 300% of current annual premiums paid by MEP for such insurance.

MEP Committee

EECI has agreed, until earlier of the Effective Time or the termination of the Merger Agreement, not to, without the consent of a majority of the then existing members of the MEP Committee, take any action (or allow its subsidiaries to take any action) intended to cause MEP GP to eliminate the MEP Committee, revoke or diminish the authority of the MEP Committee or remove or cause the removal of any director of the MEP GP Board that is a member of the MEP Committee either as a director or member of such committee.

Amendment and Supplement

At any time prior to the Effective Time, the Merger Agreement may be amended or supplemented in any and all respects by written agreement of the parties, whether before or after receipt of the Partnership Unitholder Approval, by action taken or authorized by the MEP GP Board and the EEM Board; provided, however, that the Merger Agreement may not be amended, modified or supplemented unless such amendment, modification or supplement is approved by the MEP Committee. Following receipt of the Partnership Unitholder Approval, no amendment to the provisions of the Merger Agreement may be made which by applicable law or stock exchange rule would require further approval by MEP’s limited partners, without such approval. Unless otherwise provided in the Merger Agreement, whenever a determination, decision, approval, consent, waiver or agreement of MEP or MEP GP is required pursuant to the Merger Agreement (including any determination to exercise or refrain from exercising certain rights under, or to enforce the terms of, the Merger Agreement), such determination, decision, approval, consent, waiver or agreement must be authorized by the MEP Committee and such action will not require approval of the MEP Common Unitholders.

Waiver and Consent

At any time prior to the Effective Time, any party to the Merger Agreement may waive compliance by another party or grant any consent under the Merger Agreement, whether before or after the Partnership Unitholder Approval; provided, however, that, neither MEP nor MEP GP may take or authorize any such action without the prior approval of the MEP GP Board (after consulting with the MEP Committee). Notwithstanding the foregoing, no failure or delay by MEP, MEP GP, EECI or Merger Sub in exercising any right under the Merger Agreement will operate as a waiver thereof nor will any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right under the Merger Agreement. Any agreement on the part of a party hereto to any such extension or waiver will be valid only if set forth in an instrument in writing signed on behalf of such party.

Remedies; Specific Performance

The Merger Agreement provides that the parties are entitled to an injunction or injunctions to prevent breaches of the Merger Agreement and to specifically enforce the provisions of the Merger Agreement. The Merger Agreement provides for a waiver of any requirement to obtain, furnish or post any bond or similar instrument in connection with obtaining any remedy provided by this paragraph.

Representations and Warranties

The Merger Agreement contains representations and warranties by EECI and Merger Sub, on the one hand, and MEP and MEP GP, on the other hand. These representations and warranties have been made for the benefit of the other party to the Merger Agreement and:

 

    may be intended not as statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

 

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    have been qualified by disclosures that were made to the other party in connection with the negotiation of the Merger Agreement, which disclosures may not be reflected in the Merger Agreement; and

 

    may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors.

Accordingly, these representations and warranties should not be read alone, but instead should be read only in conjunction with the information provided elsewhere in this information statement and in the documents incorporated by reference into this information statement, which may include information that updates, modifies or qualifies the information set forth in the representations and warranties.

The representations and warranties made by MEP and MEP GP relate to, among other things:

 

    due authorization of the Merger Agreement and the transactions contemplated by the Merger Agreement;

 

    capitalization;

 

    governmental approvals and legal proceedings;

 

    opinions of financial advisors;

 

    brokers and other advisors; and

 

    no other representations and warranties.

The representations and warranties made by EECI and Merger Sub relate to, among other things:

 

    corporate organization, standing and similar corporate matters;

 

    operations and ownership of Merger Sub;

 

    ownership of MEP Class A Common Units and Subordinated Units;

 

    due authorization of the Merger Agreement and the transactions contemplated by the Merger Agreement, the absence of any conflicts with third parties created by such transactions and the execution and delivery of the Support Agreement;

 

    required consents and approvals of governmental entities in connection with the transactions contemplated by the Merger Agreement;

 

    legal proceedings;

 

    access to information;

 

    information supplied in connection with this information statement and the filing of a Schedule 13E-3;

 

    brokers and other advisors;

 

    the availability of sources of immediately available funds sufficient to consummate the Merger and to pay all amounts required to be paid in connection with the transactions contemplated by the Merger Agreement; and

 

    no other representations and warranties.

Additional Agreements

The Merger Agreement also contains covenants relating to cooperation in the preparation of this information statement and additional agreements relating to, among other things, access to information, applicability of takeover statutes, public announcements and litigation.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a discussion of the material U.S. federal income tax consequences of the Merger that may be relevant to holders of Class A Common Units. This discussion is based upon current provisions of the Code, existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences to vary substantially from the consequences described below.

This discussion does not purport to be a complete discussion of all U.S. federal income tax consequences of the Merger. Moreover, the discussion focuses on holders of Class A Common Units who are individual citizens or residents of the United States (for U.S. federal income tax purposes) and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, employee benefit plans, foreign persons, financial institutions, insurance companies, real estate investment trusts (REITs), individual retirement accounts (IRAs), mutual funds, traders in securities that elect mark-to-market, persons who hold Class A Common Units as part of a hedge, straddle or conversion transaction, persons who acquired Class A Common Units by gift, or directors and employees of MEP that received (or are deemed to receive) Class A Common Units as compensation or through the exercise (or deemed exercise) of options, unit appreciation rights, phantom units or restricted units granted under a MEP equity incentive plan. Also, the discussion assumes that the Class A Common Units are held as capital assets at the time of the Merger (generally, property held for investment).

MEP has not sought a ruling from the IRS with respect to any of the tax consequences discussed below, and the IRS would not be precluded from taking positions contrary to those described herein. As a result, no assurance can be given that the IRS will agree with all of the tax characterizations and the tax consequences described below. Some tax aspects of the Merger are not certain, and no assurance can be given that the below-described opinions and/or the statements contained herein with respect to tax matters would be sustained by a court if contested by the IRS. Furthermore, the tax treatment of the Merger may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

Accordingly, MEP strongly urges each holder of Class A Common Units to consult with, and depend upon, such unitholder’s own tax advisor in analyzing the U.S. federal, state, local and foreign tax consequences particular to such unitholder of the Merger.

Tax Considerations of the Merger to Holders of Class A Common Units

Tax Characterization of the Merger. The receipt of cash in exchange for Class A Common Units pursuant to the Merger will be a taxable transaction to holders for U.S. federal income tax purposes. In general, the Merger will be treated as a taxable sale of a holder’s Class A Common Units in exchange for cash received in the Merger.

Amount and Character of Gain or Loss Recognized. A holder who receives cash in exchange for Class A Common Units pursuant to the Merger will recognize gain or loss in an amount equal to the difference between (1) the sum of (A) the amount of any cash received and (B) such holder’s share of MEP’s nonrecourse liabilities immediately prior to the Merger and (2) such holder’s adjusted tax basis in the Class A Common Units exchanged therefor (which includes such holder’s share of MEP’s nonrecourse liabilities immediately prior to the Merger).

A holder’s initial tax basis in its Class A Common Units would have been equal to the amount such holder paid for the Class A Common Units plus the holder’s share of MEP’s nonrecourse liabilities. Over time that basis would have (1) increased by (A) the holder’s share of MEP’s income and (B) any increases in the holder’s share

 

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of MEP’s nonrecourse liabilities, and (2) decreased, but not below zero, by (A) distributions from MEP, (B) the holder’s share of MEP’s losses, (C) any decreases in the holder’s share of MEP’s nonrecourse liabilities and (D) the holder’s share of MEP’s expenditures that are not deductible in computing taxable income and are not required to be capitalized.

Except as noted below, gain or loss recognized by a holder on the exchange of Class A Common Units in the Merger will generally be taxable as capital gain or loss. However, a portion of this gain or loss, which could be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to “unrealized receivables,” including depreciation recapture, or to substantially appreciated “inventory items” owned by MEP and its subsidiaries. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized upon the exchange of a Class A Common Unit pursuant to the Merger and may be recognized even if there is a net taxable loss realized on the exchange of such holder’s Class A Common Units pursuant to the Merger. Consequently, a holder may recognize both ordinary income and capital loss upon the exchange of Class A Common Units in the Merger.

Capital gain or loss recognized by a holder will generally be long-term capital gain or loss if the holder has held its Class A Common Units for more than 12 months as of the effective time of the Merger. If the holder is an individual, such long-term capital gain will generally be eligible for reduced rates of taxation. Capital losses recognized by a holder may offset capital gains and, in the case of individuals, offset no more than $3,000 of ordinary income. Capital losses recognized by holders that are corporations may only be used to offset capital gains.

The amount of gain or loss recognized by each holder in the Merger will vary depending on each holder’s particular situation, including the adjusted tax basis of the Class A Common Units exchanged by each holder in the Merger, and the amount of any suspended passive losses that may be available to a particular unitholder to offset a portion of the gain recognized by each holder. Passive losses that were not deductible by a holder in prior taxable periods because they exceeded a holder’s share of MEP’s income may be deducted in full upon the holder’s taxable disposition of its entire investment in MEP pursuant to the Merger. Each holder is strongly urged to consult its own tax advisor with respect to the specific tax consequences of the Merger to such holder, taking into account its own particular circumstances.

MEP Items of Income, Gain, Loss and Deduction for the Taxable Period Ending on the Date of the Merger. Holders of Class A Common Units will be allocated their share of MEP’s items of income, gain, loss and deduction for the taxable period of MEP ending on the date of the Merger. These allocations will be made in accordance with the terms of the MEP Partnership Agreement. A holder will be subject to U.S. federal income tax on any such allocated income and gain even if such holder does not receive a cash distribution from MEP attributable to such allocated income and gain. Any such income and gain allocated to a holder will increase the holder’s tax basis in the Class A Common Units held and, therefore, will reduce the gain, or increase the loss, recognized by such holder resulting from the Merger. Any losses or deductions allocated to a holder will decrease the holder’s tax basis in the Class A Common Units held and, therefore, will increase the gain, or reduce the loss, recognized by such holder resulting from the Merger.

 

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INFORMATION CONCERNING MEP

About MEP

MEP is a publicly traded Delaware limited partnership formed in 2013 by EEP to serve as EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. MEP’s business primarily consists of gathering unprocessed and untreated natural gas from wellhead locations and other receipt points on its systems, processing the natural gas to remove NGLs and impurities at its processing and treating facilities and transporting the processed natural gas and NGLs to intrastate and interstate pipelines for transportation to various customers and market outlets. Additionally, MEP also provides marketing services of natural gas and NGLs to wholesale customers.

Class A Common Units trade on the NYSE under the symbol “MEP.” MEP’s and MEP GP’s mailing address is 1100 Louisiana Street, Suite 3300, Houston, Texas 77002 and their telephone number is (713) 821-2000. A detailed description of MEP’s business is contained in its Annual Report on Form 10-K for the year ended December 31, 2016, which is attached as Annex D to this information statement. See “Where You Can Find More Information.”

During the past five years, neither MEP nor MEP GP has been (1) convicted in a criminal proceeding or (2) party to any judicial or administrative proceeding (except for matters that were dismissed without sanction or settlement) that resulted in a judgment, decree or final order enjoining the entity from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.

Business and Background of Natural Persons Related to MEP

Set forth below are the names, the present principal occupations or employment and the name, principal business and address of any corporation or other organization in which such occupation or employment is conducted and the five-year employment history of the current directors and executive officers of the following parties related to MEP: MEP GP, EEM, EECI and Enbridge.

During the past five years, none of the directors and executive officers of MEP GP or the persons described below have been (1) convicted in a criminal proceeding (excluding traffic violations or similar misdemeanors) or (2) party to any judicial or administrative proceeding (except for matters that were dismissed without sanction or settlement) that resulted in a judgment, decree or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws or a finding of any violation of federal or state securities laws.

 

             MEP GP             

Name

   Citizenship            Position with MEP GP        

Dan A. Westbrook

   USA    Director and Chairman of the Board

John A. Crum

   USA    Director

J. Herbert England

   USA    Director

James G. Ivey

   USA    Director

Laura B. Sayavedra

   USA    Director

Mark A. Maki

   USA    Director & Senior Vice President

R. Poe Reed

   USA    Director & President

Edmund P. Segner III

   USA    Director

Allen Capps

   USA    Controller

Stephen J. Neyland

   USA    Vice President—Finance

Kerry C. Puckett

   USA    Vice President—Engineering and
Operations, Gathering & Processing

Wanda Opheim

   Canada    Treasurer

 

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Dan A. Westbrook

Dan A. Westbrook was appointed Chairman of the Board and elected as a director of MEP GP in October 2013 and also serves on the Audit, Finance & Risk Committee. Mr. Westbrook has also served as a director of EECI and EEM since October 2007, and serves on the Audit, Finance & Risk Committee of both companies, as well as serving on Special Committees of EEM. Since 2008, he has also served on the board of the Carrie Tingley Hospital Foundation in Albuquerque, New Mexico. From 2001 to 2005, Mr. Westbrook served as president of BP China Gas, Power & Upstream, or BP, and as vice-chairman of the board of directors of Dapeng LNG, a Sino joint venture between BP subsidiary CNOOC Gas & Power Ltd. and other Chinese companies. He held executive positions with BP in Argentina, Houston, Russia, Chicago and the Netherlands before retiring from the company in January 2006. From 2013 to 2016, Mr. Westbrook served as a director of SandRidge Energy, Inc. He is a former director of Ivanhoe Mines, now known as Turquoise Hill Resources Ltd., an international mining company; Synenco Energy Inc., a Calgary-based oil sands company; and Knowledge Systems Inc., a privately-held U.S. company that provided software and consultant services to the oil and gas industry.

John A. Crum

John A. Crum was appointed a director of MEP GP on February 10, 2014 and also was appointed to serve on the Audit, Finance & Risk Committee. Since 2015, Mr. Crum has been managing partner of JAC Energy Partners, L.L.C., a company which provides advice and invests in upstream oil and gas development opportunities. He also presently serves as Chairman of the board of managers for Forty Acres Energy, L.L.C., a privately held exploration and production company. From 2011 to 2014, Mr. Crum served as President and Chief Executive Officer and as director of Midstates Petroleum Company, Inc., where he led the initial public offering of the oil and gas exploration and production company in 2012. He also served on the board of directors of Coskata, Inc., a private biofuel technology company, from 2012 to 2015. From 1995 to 2011, Mr. Crum served in a number of senior management roles for Apache Corporation international divisions, and ultimately served as Co-Chief Operating Officer and President, North America from 2009 to 2011. Some previous positions held by Mr. Crum include Vice President of Engineering and Operations of Aquila Energy Corporation from 1993 to 1995 and District Manager and Regional Manager for Pacific Enterprises Oil Company from 1986 to 1993.

J. Herbert England

J. Herbert England was elected a director of MEP GP in October 2013 and serves as the Chairman of the Audit Finance & Risk Committee of MEP GP. Mr. England has also served as a director of each of EECI and EEM since July 2012 and serves as the Chairman of the Audit, Finance & Risk Committee of both companies. In addition, Mr. England serves on the Enbridge board of directors for whom he also is Chairman of the Audit, Finance & Risk Committee, and on the board of directors of FuelCell Energy, Inc. He has been Chair & Chief Executive Officer of Stahlman-England Irrigation Inc., a contracting company in southwest Florida, since 2000. From 1993 to 1997, Mr. England was the Chair, President & Chief Executive Officer of Sweet Ripe Drinks Ltd., a fruit beverage manufacturing company. Prior to 1993, Mr. England held various executive positions with John Labatt Limited, a brewing company, and its operating companies, Catelli Inc., a food manufacturing company, and Johanna Dairies Inc., a dairy company.

Laura Buss Sayavedra

Laura Buss Sayavedra was elected a director of MEP GP, EECI, and EEM in February 2017. Also in February 2017, Ms. Sayavedra was appointed as the Vice President of Sponsored Vehicles of Spectra Energy Partners GP, LLC (the “Spectra General Partner”), the general partner of Spectra Energy Partners (DE) GP, LP, which is the general partner of Spectra Energy Partners, LP. Ms. Sayavedra served as Vice President and Treasurer for Spectra Energy Corp from January 2014 to February 2017. Ms. Sayavedra previously served as Vice President-Strategy for Spectra Energy Corp in 2013, as Vice President and Chief Financial Officer of the Spectra General Partner from 2008 to 2013, and as Vice President, Strategic Development and Analysis of Spectra Energy Corp from 2007 to 2008. Prior to that, Ms. Sayavedra served as a Vice President of Operations & Analytics of Duke Energy North America, and also served in various finance and business development roles of increasing responsibility.

 

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James G. Ivey

James G. Ivey was appointed a director of MEP GP on February 10, 2014 and also was appointed to serve on the Audit, Finance & Risk Committee. From 2014 to February 2017, Mr. Ivey co-headed Pintail Oil and Gas, an exploration and production company. Mr. Ivey currently serves on the board of directors of privately held independent power producer, National Energy & Gas Transmission, Inc., since 2004 and Mach Gen LLC from 2004 to 2014. His prior experience includes serving Milagro Exploration from 2009 to 2012 in the role of Executive Vice President and Chief Financial Officer from 2009 to 2010 and then President and Chief Executive Officer from 2010 to 2012. From 2006 to 2008, Mr. Ivey was Executive Vice President and Chief Financial Officer of Cobalt International Energy. From 2004 to 2006, Mr. Ivey served Markwest Hydrocarbon as Senior Vice President and Chief Financial Officer. His previous background includes serving as the Corporate Treasurer for each of Williams Companies from 1995 to 2004 and Arkla Gas from 1982 to 1995, as well as other financial and engineering positions with Conoco and Fluor from 1973 to 1981.

Mark A. Maki

Mark A. Maki was appointed Senior Vice President of MEP GP in February 2014, and he has served as a director of MEP GP since May 2013. Previously from October 2013 until February 2014, he served as Principal Executive Officer of MEP GP. Mr. Maki previously served as President of MEP GP from May 2013 to October 2013. In October 2016, Mr. Maki was elected to serve Enbridge as Senior Vice President – Finance. He was also appointed President and Principal Executive Officer of EECI and EEM on January 30, 2014 and has served both companies as a director since October 2010. Mr. Maki previously served as President of EEM and Senior Vice President of EECI from October 2010. He also served Enbridge in the functional title of Acting President, Gas Pipelines during 2013. Mr. Maki previously served as Vice President – Finance of EECI and EEM from July 2002 to October 2010. Prior to that time, Mr. Maki served as Controller of EECI and EEM from June 2001, and prior to that, as Controller of Enbridge Pipelines from September 1999.

R. Poe Reed

R. Poe Reed joined Enbridge on September 28, 2015 as Vice President & Chief Commercial Officer of MEP GP and was elected as a director effective November 30, 2015. In February of 2017, his position changed to President of MEP GP. Previously, Mr. Reed was President and Chief Executive Officer of Caliber Midstream from June 2014 to September 2015. Prior to that Mr. Reed was with CenterPoint Energy from January 2011 through June 2014, most recently from December 2013 through June 2014 serving as Executive Vice President and Chief Commercial Officer for Enable Midstream, an MLP in which CenterPoint Energy holds a majority interest and from January 2011 to December 2013 serving as Senior Vice President and Chief Commercial Officer for Interstate Pipelines for CenterPoint Energy. From July 2009 through January 2011, he served as Vice President of natural gas and NGL marketing at DCP Midstream. Before joining DCP Midstream, Mr. Reed worked in various executive and non-executive capacities with some of the predecessors of DCP, including Duke Energy Field Services Canada, PanEnergy and Texas Eastern.

Edmund P. Segner III

Edmund P. Segner III was appointed a director of MEP GP on February 10, 2014. Mr. Segner is currently a professor in the Department of Civil and Environmental Engineering at Rice University and serves on the boards of directors of three other companies and audit committees, as follows: Bill Barrett Corp., an oil and gas exploration and production company, since August 2009; Archrock GP LLC, formerly Exterran GP LLC, the general partner of Archrock Partners, L.P., an MLP which provides contract operations since May 2009; and Laredo Petroleum, Inc., a Permian oil and gas exploration and development company since August 2011. Mr. Segner retired from EOG Resources, Inc. in 2008. He had held several offices at EOG during his tenure from 1997 to 2008 including President, Chief of Staff and Director and principal financial officer. Formerly, from 1988 to early 1998, Mr. Segner held several positions with Enron Corporation, including Vice President, Senior Vice President and Executive Vice President. Previously, Mr. Segner also served on the boards of Seahawk Drilling from 2009 to 2011 and of Universal Compression Holdings from 2000 to 2002. He has also served as a member of the board or as a trustee for several nonprofit organizations.

 

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Allen Capps

Allen C. Capps was appointed Controller of the MEP GP in February of 2017. He is also Controller of Spectra Energy Partners GP, LLC and was appointed Vice President and Controller of Spectra Energy Corp in January 2012. He previously served as Vice President, Business Development, Storage and Transmission, for Union Gas from April 2010. Prior to such time, Mr. Capps served as Vice President and Treasurer for Spectra Energy Corp from December 2007 until April 2010. Mr. Capps has a strong knowledge of the energy industry and years of experience in senior finance and treasury roles.

Stephen J. Neyland

Stephen J. Neyland was appointed Vice President – Finance of MEP GP in May 2013. Mr. Neyland has served as Vice President - Finance of EECI and EEM since October 2010 and as a director of EECI and EEM since February 2017. Mr. Neyland was previously Controller of EECI and EEM effective September 2006. Prior to his appointment, he served as Controller - Natural Gas from January 2005, Assistant Controller from May 2004 to January 2005 and in other managerial roles in finance and accounting from December 2001 to May 2004. Prior to joining Enbridge, Mr. Neyland was Controller of Koch Midstream Services from 1999 to 2001.

Kerry C. Puckett

Kerry C. Puckett was appointed Vice President – Engineering and Operations, Gathering & Processing of MEP GP in May 2013. Mr. Puckett also served as Vice President – Engineering and Operations, Gathering & Processing of EECI and EEM from October 2007 to April 2014. Prior to this appointment, he served as General Manager of Engineering and Operations from 2004 and Manager of Operations from 2002 to 2004. Prior to joining Enbridge, he served as Manager of Business Development for Sid Richardson Energy Services Company.

Wanda Opheim

Wanda Opheim was appointed to the role of Treasurer of EEM, EECI and MEP GP in February of 2017. She was also appointed to the role of Senior Vice President, Treasury of Enbridge in February 2017. Prior to that, she held the role of Senior Vice President, Chief Accounting Officer of Enbridge. Since joining Enbridge 25 years ago, Ms. Opheim has held roles of increasing responsibility within the Enbridge finance group most recently as Senior Vice President, Finance. Prior to that she was the Vice President, Corporate Planning and Development, Vice President, Treasury & Tax, Senior Director, Tax Services and Manager, Cash Management & Banking.

 

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The address of each of the directors and executive officers of MEP GP listed above is 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

 

     EEM  

Position with EEM, as delegate of EECI, general
partner of EEP

Name

   Citizenship  

Jeffrey A. Connelly

   USA   Director

J. Richard Bird

   Canada   Director

J. Herbert England

   USA   Director

Stephen J. Neyland

   USA   Director and Vice President—Finance

Laura B. Sayavedra

   USA   Director

D. Guy Jarvis

   Canada   Director and Executive Vice President—Liquids Pipelines

Mark A. Maki

   USA   Director and President

William S. Waldheim

   USA   Director

Dan A. Westbrook

   USA   Director

John K. Whelen

   Canada   Director

Mark R. Boyce

   Canada   Vice President—Liquids Pipelines Law

David W. Bryson

   Canada   Senior Vice President—Liquids Pipelines; Operations

Leo J. Golden

   Canada   Vice President—Major Projects

Wanda Opheim

   Canada   Treasurer

Allen Capps

   USA   Controller

Christopher J. Johnston

   Canada   Vice President

Bradley F. Shamla

   USA   Vice President—Liquids Pipelines; Operations

Leon A. Zupan

   Canada   Executive Vice President—Liquids Pipelines, Operations

Jeffrey A. Connelly

Jeffrey A. Connelly was elected as Chairman of the Board of Directors of EECI, in July 2012 and as a director of the EECI and EEM in January 2003. Previously, Mr. Connelly served as Chairman of the Audit, Finance & Risk Committee of EECI and EEM. Mr. Connelly also served as Executive Vice President, Senior Vice President and Vice President of the Coastal Corporation from 1988 to 2001.

J. Richard Bird

J. Richard Bird was elected a director of EECI and EEM in October 2012. He retired from Enbridge in early 2015, having served as Executive Vice President, Chief Financial Officer and Corporate Development, and various other roles, including: Executive Vice President Liquids Pipelines, Senior Vice President Corporate Planning and Development, and Vice President and Treasurer during his tenure with Enbridge which began in 1995. Mr. Bird serves on the Board of Directors or Trustees of Enbridge Pipelines Inc., Enbridge Income Fund Holdings Inc. and Bird Construction Company Inc. He is a member of the Board of Directors of the Alberta Investment Management Company and chairman of its audit committee. Mr. Bird is also a member of the Investment Committee of the University of Calgary Board of Governors. He was named Canada’s CFO of the Year for 2010. He holds a Bachelor of Arts degree from the University of Manitoba, and a Masters of Business Administration and PhD from the University of Toronto and has completed the Advanced Management Program at Harvard Business School.

D. Guy Jarvis

D. Guy Jarvis was appointed Executive Vice President – Liquids Pipelines and a director of EECI and EEM on March 1, 2014. Mr. Jarvis was appointed President of the Liquids Pipelines division of Enbridge on March 1, 2014, assuming responsibility for all of Enbridge’s crude oil and liquids pipeline businesses across North

 

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America. Prior to this, he was Chief Commercial Officer, Liquids Pipelines from October 2013 to March 2014. From September 2011 to October 2013, Mr. Jarvis served as President of Enbridge Gas Distribution, providing overall leadership to Enbridge Gas Distribution, Canada’s largest natural gas utility, as well as Enbridge Gas New Brunswick, Gazifère and St. Lawrence Gas. Previously at Enbridge Pipelines Inc., Mr. Jarvis served as Senior Vice President, Investor Relations & Enterprise Risk; Senior Vice President, Business Development from March 2008 to October 2010; Vice President, Upstream Development for Enbridge Pipelines Inc.; and Vice President, Gas Services.

William S. Waldheim

William S. Waldheim was elected as a director of EECI and EEM in February 2016 and serves on the Audit, Finance & Risk Committee of EECI and EEM, as well as on Special Committees of EEM. He previously served as President of DCP Midstream Partners LP where he had overall responsibility for DCP partnership affairs including commercial, trading and business development until his retirement in 2015. Prior to this, Mr. Waldheim was President of Midstream Marketing and Logistics for DCP Midstream and managed natural gas, crude oil and natural gas liquids marketing and logistics. From 2005 to 2008 he was Group Vice President of commercial for DCP Midstream, managing its upstream and downstream commercial business. Mr. Waldheim started his professional career in 1978 with Champlin Petroleum as an auditor and financial analyst and served in roles involving NGL and crude oil distribution and marketing. He served as Vice President of NGL and Crude Oil Marketing for Union Pacific Fuels from 1987 until 1998 at which time they were acquired by DCP.

John K. Whelen

John K. Whelen was elected a director of EECI and EEM on October 31, 2014. Mr. Whelen also serves Enbridge as Executive Vice President and Chief Financial Officer since October 15, 2014, and as such leads the financial reporting function, and tax and treasury functions for Enbridge. Prior to this, from July 2014, to October 2014, Mr. Whelen was Senior Vice President, Finance for Enbridge and from April 2011 to July 2014 he was Senior Vice President and Controller. From September 2006 to April 2011, Mr. Whelen was Senior Vice President, Corporate Development for Enbridge. Additionally, Mr. Whelen has served as the chief financial officer, and then president of Enbridge Income Fund. Mr. Whelen joined Enbridge in 1992 as Manager of Treasury at what has become Enbridge Gas Distribution and has held a series of executive positions during his tenure with Enbridge.

Mark R. Boyce

Mark R. Boyce was appointed Vice President, Liquids Pipelines Law and Assistant Corporate Secretary of EECI and EEM in June 2016. Mr. Boyce also currently serves as Vice President, Liquids Pipelines - Law of several Enbridge subsidiaries. Prior to that, from May 2015 to June 2016, he was Vice President, Chief Compliance & Privacy Officer for Enbridge and from April 2012 until May 2015, he was Vice President & Chief Compliance Officer for Enbridge, responsible for the development and performance of compliance, training and ethics programs. Prior to April 2012, Mr. Boyce served Enbridge Gas Distribution (“EGD”) as Vice President, Law & Information Technology, a position he had progressed to after joining Enbridge as a corporate solicitor for the predecessor of EGD in August 1993.

David. W. Bryson

David W. Bryson was appointed Senior Vice President – Liquids Pipelines, Operations of EECI and EEM in October 2016. Since June 2016, Mr. Bryson also serves the Liquids Pipelines Division of Enbridge as Senior Vice President, Operations, Liquids Pipelines, responsible for North American field operations across the Mainline, Gathering and Storage assets of the Liquids Pipelines Division. Prior to that, from April 2014, he was Vice President, Customer Service, Liquids Pipelines, after serving from July 2012 to April 2014 as Vice President, Asset Performance & Development and Vice President, Strategy & Integrated Services. Mr. Bryson joined Enbridge in 1994 via Enbridge Gas Distribution as a manager and progressed into the Major Projects Division in 2008, where he held various roles directing several of the major projects and programs, and progressed to the Liquids Pipelines division in 2012.

 

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Leo J. Golden

Leo J. Golden was appointed Vice President – Major Projects of EECI and EEM on April 30, 2015. Since July 2014 he also serves Enbridge as a Vice President responsible for the execution of Renewables, Power and Gas Processing projects in both Canada and the U.S. From November 2011 to July 2014, Mr. Golden served Enbridge as Vice President, Major Projects Execution for certain subsidiaries. From April 2008 and November 2011, he was Vice President of Pipeline and Green Energy Projects and Vice President of the Alberta Clipper Project for certain Enbridge subsidiaries. Mr. Golden has served Enbridge in many capacities for over 25 years, having joined in September 1990. His roles have included Director and Project Director of several Enbridge projects and areas, including Alberta Clipper, Shipper Services, Oil Sands and Acquisitions, Rates Assistant, Rates Analyst, Planning Analyst, Energy Analyst, and Manager of Business Development. In 1989, prior to joining Enbridge, Mr. Golden was a policy analyst with the Vancouver Stock Exchange.

Christopher J. Johnston

Christopher J. Johnston was appointed Vice President of EECI and EEM in February of 2017. He joined Enbridge as Vice President and Controller July 1, 2014. Prior to joining Enbridge, Mr. Johnston worked at Deloitte LLP where he was Partner in their Assurance and Advisory practice for eight years.

Bradley F. Shamla

Bradley F. Shamla was appointed Vice President – U.S. Operations, Liquids Pipelines of EECI and EEM in April 2013. He previously served Enbridge as Vice President, Market Development since October 2010. Mr. Shamla was previously a senior director in the Business Development Group of Enbridge since 2008 and before that he was general manager in the Liquids Pipelines Operations Group, having joined Enbridge in 1991 and worked in a number of areas, including Operations, Engineering and Administration, both in the U.S. and Canada.

Leon A. Zupan

Leon A. Zupan currently serves EECI and EEM as Executive Vice President – Liquids Pipelines, Operations since April 2014. Previously, from April 2013 to April 2014, he served as Executive Vice President. In April 2013, he resigned as a director and as Executive Vice President – Gas Pipelines of EECI and EEM, positions which he held since April 2012, to accept a new position with Enbridge as Chief Operating Officer of Liquids Pipelines. Prior to April 2012, he had served EECI and EEM as Vice President – Operations since 2004. Prior to May of 2013, he served Enbridge as Senior Vice President – Gas Pipelines, overseeing Enbridge’s U.S. and Canadian gas pipelines businesses from February 2012 to April 2013. Prior to that, Mr. Zupan had served Enbridge as Vice President – Operations since 2004. Mr. Zupan joined Enbridge in 1987 and has experience across a range of businesses.

For biographical information about J. Herbert England, Mark A. Maki, Dan A. Westbrook, Stephen J. Neyland, Laura B. Sayavedra, Allen Capps and Wanda Opheim, see the list of directors and executive officers of MEP GP above.

 

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The address of each of the directors and executive officers of EEM listed above is 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

 

     EECI   

Position with EECI

Name

       Citizenship       

Jeffrey A. Connelly

   USA    Director

J. Richard Bird

   Canada    Director

J. Herbert England

   USA    Director

Stephen J. Neyland

   USA    Director and Vice President—Finance

Laura B. Sayavedra

   USA    Director

D. Guy Jarvis

   Canada    Director and Executive Vice President—Liquids Pipelines

Mark A. Maki

   USA    Director and President

William S. Waldheim

   USA    Director

Dan A. Westbrook

   USA    Director

John K. Whelen

   Canada    Director

Mark R. Boyce

   Canada    Vice President—Liquids Pipelines Law

David W. Bryson

   Canada    Senior Vice President—Liquids Pipelines; Operations

Leo J. Golden

   Canada    Vice President—Major Projects

Wanda Opheim

   Canada    Treasurer

Allen Capps

   USA    Controller

Christopher J. Johnston

   Canada    Vice President

Bradley F. Shamla

   USA    Vice President—Liquids Pipelines; Operations

Leon A. Zupan

   Canada    Executive Vice President—Liquids Pipelines, Operations

For biographical information about J. Herbert England, Mark A. Maki, Dan A. Westbrook, Stephen J. Neyland, Laura B. Sayavedra, Allen Capps and Wanda Opheim, see the list of directors and executive officers of MEP GP above. For biographical information about Jeffrey A. Connelly, J. Richard Bird, D. Guy Jarvis, William S. Waldheim, John K. Whelen, Mark R. Boyce, David W. Bryson, Leo J. Golden, Christopher J. Johnston, Bradley F. Shamla and Leon A. Zupan, see the list of directors and executive officers of EEM above.

 

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The address of each of the directors and executive officers of EECI listed above is 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

 

     EI     

Name

       Citizenship       

Position with Enbridge

Pamela L. Carter

   USA    Director

Clarence P. Cazalot, Jr.

   USA    Director

Marcel R. Coutu

   Canada    Director

Gregory L. Ebel

   USA    Director and Chairman of the Board

J. Herbert England

   USA    Director

Charles W. Fischer

   Canada    Director

V. Maureen Kempston Darkes

   USA and Canada    Director

Michael McShane

   USA    Director

Al Monaco

   Canada    Director, President and Chief Executive Officer

Michael E.J. Phelps

   Canada    Director

Rebecca B. Roberts

   USA    Director

Dan C. Tutcher

   USA    Director

Catherine L. Williams

   Canada    Director

Cynthia L. Hansen

   Canada    Executive Vice President, Utilities and Power Operations

D. Guy Jarvis

   Canada    Executive Vice President & President, Liquids Pipelines

Byron C. Neiles

   Canada    Executive Vice President, Corporate Services

Karen L. Radford

   Canada    Executive Vice President & Chief Transformation Officer

Robert R. Rooney

   Canada    Executive Vice President & Chief Legal Officer

John K. Whelen

   Canada    Executive Vice President & Chief Financial Officer

William T. Yardley

   USA    Executive Vice President & President, Gas Transmission & Midstream

Vern D. Yu

   Canada    Executive Vice President & Chief Development Officer

Pamela L. Carter

Ms. Carter is the retired President of Cummins Distribution Business, a division of Cummins Inc., a global manufacturer of diesel engines and related technologies. She assumed that role in 2008 and served in that position until she retired in April 2015. She previously served as President – Cummins Filtration, then as Vice President and General Manager of Europe, Middle East and Africa business and operations for Cummins Inc. since 1999. Ms. Carter served as Vice President and General Counsel of Cummins Inc. from 1997 to 1999. Prior to joining Cummins Inc., she served as the Attorney General for the State of Indiana from 1993 to 1997. In 2010, Ms. Carter was appointed to the Export-Import Bank of the United States’ sub-Saharan Africa Advisory Council. Ms. Carter holds a BA (Bachelor of Arts) from the University of Detroit Mercy, a MSW (Master of Social Work) from University of Michigan and a JD (Juris Doctor) from Indiana University Law School.

Clarence P. Cazalot, Jr.

Mr. Cazalot is the retired Executive Chairman, President and Chief Executive Officer of Marathon Oil Corporation (Marathon) (public exploration and production company). He was Executive Chairman of Marathon from August 2013 to December 2013; Chairman from 2011 to 2013; and President, Chief Executive Officer and

 

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director from 2002 to August 2013. From 2000 to 2001, he served as Vice Chairman of USX Corporation and President of Marathon. Mr. Cazalot held various executive positions with Texaco Inc. from 1972 to 2000. He is a member of the Advisory Board of the James A. Baker III Institute for Public Policy, the Board of Visitors of the University of Texas M.D. Anderson Cancer Center, the Memorial Hermann Health Systems Board and the LSU Foundation. Mr. Cazalot holds a BS (Bachelor of Science in Geology) from Louisiana State University, Baton Rouge, an honorary PhD (Doctor of Philosophy, Humane Letters) from Louisiana State University and an honorary PhD (Doctor of Philosophy, Engineering) from Colorado School of Mines.

Marcel R. Coutu

Mr. Coutu was the Chairman of Syncrude Canada Ltd. (integrated oil sands project) from 2003 to 2014 and was the President and Chief Executive Officer of Canadian Oil Sands Limited from 2001 until January 2014. From 1999 to 2001, he was Senior Vice President and Chief Financial Officer of Gulf Canada Resources Limited. Prior to 1999, Mr. Coutu held various executive positions with TransCanada PipeLines Limited and various positions in the areas of corporate finance, investment banking and mining and oil and gas exploration and development. Mr. Coutu holds an HBSc (Bachelor of Science, Honours Earth Science) and an MBA (Master of Business Administration) from the University of Western Ontario.

Gregory L. Ebel

Mr. Ebel served as Chairman, President and CEO of Spectra Energy from January 1, 2009 to February 27, 2017 at which time became a Director of Enbridge and Chair of the Enbridge Board. Prior to that time, Mr. Ebel served as Spectra Energy’s Group Executive and Chief Financial Officer beginning in January 2007. He served as President of Union Gas Limited from January 2005 until January 2007, and Vice President, Investor & Shareholder Relations of Duke Energy Corporation from November 2002 until January 2005. Mr. Ebel joined Duke Energy in March 2002 as Managing Director of Mergers and Acquisitions in connection with Duke Energy’s acquisition of Westcoast Energy Inc. Mr. Ebel holds a BA (Bachelor of Arts, Honours) from York University.

Charles W. Fischer

Mr. Fischer was the President & Chief Executive Officer of Nexen Inc. (oil and gas company) from 2001 to 2008. From 1994 to 2001, Mr. Fischer held various executive positions within Nexen Inc., including the positions of Executive Vice President & Chief Operating Officer in which he was responsible for all Nexen’s conventional oil and gas business in Western Canada, the US Gulf Coast and all international locations, as well as oil sands, marketing and information systems activities worldwide. Prior thereto, Mr. Fischer held positions with Dome Petroleum Ltd. (oil and gas company), Hudson’s Bay Oil & Gas Ltd. (oil and gas company), Bow Valley Industries Ltd. (oil and gas company), Sproule Associates Ltd. (petroleum consulting firm) and Encor Energy Ltd. (oil and gas company). Mr. Fischer holds a BSc (Bachelor of Science in Chemical Engineering) and an MBA (Master of Business Administration), both from the University of Calgary.

V. Maureen Kempston Darkes

Ms. Kempston Darkes is the retired Group Vice President and President Latin America, Africa and Middle East, General Motors Corporation (automotive corporation and vehicle manufacturer). From 1994 to 2001, she was the President and General Manager of General Motors of Canada Limited and Vice President of General Motors Corporation. Ms. Kempston Darkes holds a BA (Bachelor of Arts) and an LLB (Bachelor of Laws), both from the University of Toronto.

Michael McShane

Mr. McShane served as a director and as President and Chief Executive Officer of Grant Prideco, Inc. (supplier of drill pipe and drill stem accessories) from June 2002 and assumed the role of Chairman of the Board of Grant Prideco beginning in May 2004. Mr. McShane retired from Grant Prideco following its acquisition by National Oilwell Varco, Inc. in April 2008. Prior to joining Grant Prideco, Mr. McShane was Senior Vice President-Finance and Chief Financial Officer and director of BJ Services Company LLC beginning in 1990. Mr. McShane serves as an Advisor to Advent International Corporation, a global private equity firm.

 

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Mr. McShane also serves as an advisor to TPH Asset Management, LLC. Mr. McShane holds a BBA (Bachelor of Business Administration) from the University of Texas and has a Chartered Professional Accountant designation.

Al Monaco

Mr. Monaco joined Enbridge in 1995 and has held increasingly senior positions. He has been President & Chief Executive Officer of Enbridge since October 1, 2012 and has served as President of Enbridge since February 27, 2012. Mr. Monaco holds an MBA (Master of Business Administration) from the University of Calgary and has a Chartered Professional Accountant designation.

Michael E.J. Phelps

Mr. Phelps is Chairman and founder of Dornoch Capital Inc., a private investment company. From January 1988 to 2002, he served as President and Chief Executive Officer, and subsequently as Chairman and Chief Executive Officer, of Westcoast Energy Inc., based in Vancouver, B.C. In 2001, Mr. Phelps was appointed as an Officer to the Order of Canada. In 2003, the Canadian government appointed Mr. Phelps as Chairman of the Wise Persons’ Committee, a panel developed to review Canada’s system of securities regulation. Mr. Phelps holds a BA (Bachelor of Arts) and LLB (Bachelor of Laws) from the University of Manitoba and an LLM (Master of Laws) from the London School of Economics.

Rebecca B. Roberts

Ms. Roberts was President of Chevron Pipe Line Company (pipeline company) from 2006 to 2011 where she was responsible for Chevron’s US network of pipelines transporting crude oil, natural gas and petroleum products and for supporting pipeline development projects worldwide. From 2003 to 2006, she was President of Chevron Global Power Generation which owned and operated assets in the US and Asia and provided technical support globally. She held various other management and technical positions with Chevron, its predecessors and its subsidiaries from 1974 to 2003. Ms. Roberts holds a BSc (Bachelor of Science) in Chemistry from McNeese State University.

Dan C. Tutcher

Mr. Tutcher has been President, Chief Executive Officer & Chair of the Board of Trustees of Center Coast MLP & Infrastructure Fund since 2013. Since its inception in 2007, Mr. Tutcher has also been a Principal in Center Coast Capital Advisors L.P. (investment adviser). He was the Group Vice President, Transportation South of Enbridge, as well as President of Enbridge Energy Company, Inc. (general partner of Enbridge Energy Partners, L.P. and an indirect, wholly-owned subsidiary of Enbridge) and Enbridge Energy Management, L.L.C. (public management company in which Enbridge holds 100% of the unlisted voting shares) from May 2001 until retirement on May 1, 2006. From 1992 to May 2001, he was the Chair of the Board of directors, President & Chief Executive Officer of Midcoast Energy Resources, Inc. Mr. Tutcher holds a BBA (Bachelor of Business Administration) from Washburn University.

Catherine L. Williams

Ms. Williams was the Chief Financial Officer for Shell Canada Limited (oil and gas company) from 2003 to 2007. Prior thereto, she held various positions with Shell Canada Limited, Shell Europe Oil Products, Shell Canada Oil Products and Shell International (oil and gas companies) from 1984 to 2003. Ms. Williams holds a BA (Bachelor of Arts) from the University of Western Ontario and an MBA (Master of Business Administration, Finance) from Queen’s School of Business (now Smith School of Business at Queen’s University).

Cynthia L. Hansen

Cynthia Hansen was appointed to the position of President, Gas Distribution and Power on June 1, 2016. Cynthia has more than 17 years of experience working in financial, operational and safety leadership roles within Enbridge, most recently as Senior Vice President, Operations within Liquids Pipelines. Prior to joining Enbridge, she worked as a Principal for PricewaterhouseCoopers.

 

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Byron C. Neiles

Byron Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles had previously held the role of Senior Vice President, Major Projects, Enterprise Safety and Operational Reliability at Enbridge, and had been Senior Vice President of Major Projects since November 2011, after joining Enbridge’s Major Projects group in April 2008. Mr. Neiles has also acted as Vice President of Customer, Regulatory and Public Affairs, as well as Legal Affairs, with Enbridge Gas Distribution in Toronto. Prior to joining Enbridge Pipelines Inc. in Edmonton, in 1994, he was a Policy Advisor to two Canadian federal energy ministers in Ottawa, and held corporate affairs roles with an electricity and natural gas utility.

Karen L. Radford

Karen Radford was appointed Executive Vice President and Chief Transformation Officer on May 2, 2016. Karen previously held the position of Executive Vice President, People, Planet & Partners, leading Enbridge’s Shared Services—including Human Resources, Corporate Social Responsibility, the Public Affairs & Communications teams, Workplace Solutions and Aviation. A biologist by training, Karen joined Enbridge in 2011 after spending 20 years in the telecom business. She served from 2004 through 2011 as a member of the executive leadership team at TELUS, which included roles as President of Business Solutions, President of Partner Solutions, President of TELUS International, and President of TELUS Quebec.

Robert R. Rooney

Bob Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017. Before joining Enbridge, Bob was Managing Director of a start-up oil and gas company. Prior to that, he was Executive Vice President, Corporate of Talisman Energy Inc., then served as Vice Chairman and director of Repsol Oil & Gas Canada Inc. In addition, Bob was a partner at Bennett Jones LLP where he was a member of the executive committee and co-leader of the Energy and Natural Resources Group.

William T. Yardley

Bill Yardley was appointed Executive Vice President and President of Gas Transmission and Midstream effective February 27, 2017. He also serves as President and Chief Executive Officer of Spectra Energy Partners, LP. Previously, Mr. Yardley was president of Spectra Energy’s U.S. Transmission and Storage business, leading the business development, project execution, operations and environment, health and safety efforts associated with Spectra Energy’s U.S. portfolio of assets. Mr. Yardley joined Spectra Energy’s predecessor company, Duke Energy Gas Transmission, in 2000 as general manager of marketing. He later served as vice president of marketing and business development and as group vice president of Northeastern U.S. assets and operations.

Vern D. Yu

Vern Yu was appointed Executive Vice President and Chief Development Officer on May 2, 2016. Previously, Mr. Yu served as Senior Vice President, Corporate Planning and Chief Development Officer. He has been at the helm of Enbridge’s Corporate Development team since July 1, 2014. Prior to joining Corporate Development, Mr. Yu served as Senior Vice President of Business and Market Development for Enbridge’s Liquids Pipelines division. Mr. Yu has been part of the Enbridge team for more than two decades, after joining the company in 1993 in Toronto, and has held a series of roles with increasing responsibility in the company’s corporate and financial areas. Prior to joining Enbridge, Mr. Yu worked as an engineer at TransCanada Corporation and Bow Valley Industries.

For biographical information about J. Herbert England, see the list of directors and officers of MEP GP above. For biographical information about D. Guy Jarvis and John K. Whelen, see the list of directors and officers of EEM above.

The address of each of the directors and executive officers of Enbridge listed above is 200, 425—1st Street S.W., Calgary, Alberta, Canada T2P 3L8.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following selected historical consolidated financial data as of and for each of the five years in the period ended December 31, 2016, are derived from MEP’s audited consolidated financial statements. You should read the following data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the related notes thereto set forth in MEP’s Annual Report on Form 10-K for the year ended December 31, 2016, which is attached as Annex D to this information statement. See “Where You Can Find More Information.”

 

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For periods prior to the closing of MEP’s initial public offering on November 13, 2013, the selected data presented represents the selected historical consolidated financial data for MOLP, as MEP’s predecessor. The selected data covering periods prior to the closing of the IPO may not necessarily be indicative of the actual results of operations had MEP operated separately during those periods.

 

    December 31,  
    2016     2015     2014     2013     2012(1)  
    (in millions, except per unit amounts)  

Consolidated Statement of Income Data:(2)

         

Operating revenues(3)

  $ 1,966.0     $ 2,842.7     $ 5,894.3     $ 5,593.6     $ 5,357.9  

Operating expenses(3)

    2,118.6       3,125.2       5,741.6       5,528.5       5,186.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

    (152.6     (282.5     152.7       65.1       171.4  

Interest expense, net

    (33.3     (29.5     (16.7     (1.7     —    

Equity in earnings of joint ventures

    30.0       29.2       13.2       —         —    

Other income (expense)

    0.9       (0.3     (0.3     (1.2     (0.1

Income tax expense

    (2.0     (1.4     (4.6     (8.3     (3.8
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ (157.0   $ (284.5   $ 144.3     $ 53.9     $ 167.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Predecessor income prior to initial public offering (from January 1, 2013 through November 12, 2013)

        $ 56.3    
       

 

 

   

Net loss subsequent to initial public offering to Midcoast Energy Partners, L.P. (from November 13, 2013 through December 31, 2013)

        $ (2.4  
       

 

 

   

Net income (loss) attributable to noncontrolling interest

  $ (57.1   $ (120.6   $ 80.2     $ (0.6  
 

 

 

   

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.

  $ (99.9   $ (163.9   $ 64.1     $ (1.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to limited partner ownership interest(4)

  $ (98.0   $ (160.5   $ 62.8     $ 19.7     $ 64.0  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per limited partner unit (basic and diluted)(4)

  $ (2.17   $ (3.55   $ 1.39     $ 0.68     $ 2.40  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions paid per limited partner unit outstanding

  $ 1.43     $ 1.40     $ 1.14      
 

 

 

   

 

 

   

 

 

     

Financial Position Data (at year end):(2)(5)

         

Property, plant and equipment, net

  $  4,114.5     $  4,226.3     $  4,159.7     $  4,082.3     $  3,963.0  

Total assets(6)

    4,916.0       5,272.1       5,752.1       6,033.6       5,667.4  

Long-term debt, excluding current maturities(6)

    818.5       888.2       758.0       332.2       —    

Partners’ capital:

         

Predecessor partner interest

    —         —         —         —         4,707.1  

Class A common units

    441.0       522.2       634.2       495.3       —    

Subordinated units

    980.8       1,062.0       1,174.0       1,035.1       —    

General Partner units

    49.3       43.3       47.8       42.2       —    

Accumulated other comprehensive income (loss)

    (0.4     (0.9     11.6       (3.1     7.1  

Noncontrolling interest

    2,299.1       2,405.7       2,529.0       2,983.2       —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital

  $ 3,769.8     $ 4,032.3     $ 4,396.6     $ 4,552.7     $ 4,714.2  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data:(2)(5)

         

Cash flows provided by operating activities

  $ 226.9     $ 207.0     $ 159.1     $ 420.9     $ 352.7  

Cash flows used in investing activities

  $ 37.1     $ 197.4     $ 231.3     $ 522.3     $ 614.5  

Cash flows provided (used) by financing activities

  $ (200.4   $ 8.4     $ 67.3     $ 106.3     $ 261.8  

Additions to property, plant and equipment, acquisitions and investment in joint venture included in investing activities, net of cash acquired

  $ 67.3     $ 239.1     $ 274.6     $ 462.9     $ 621.1  

 

(1) Represents the Predecessor historical information.

 

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(2) Our income statement, financial position and cash flow data reflect the following acquisitions and dispositions:

 

Date of Acquisition/Disposition

  

Description of Acquisition/Disposition

August 2016

  

Disposition of trucks, trailers and related facilities

July 2015

   Disposition of propylene pipeline

July 2015

  

Disposition of non-core Tinsley crude oil pipeline, storage facilities and docks

February 2015

   Acquisition of a Texas midstream business

 

(3) Decreases in “Operating revenues” and “Commodity costs” for the years ended December 31, 2016 and 2015, as compared to prior years, are primarily due to decreases in commodity prices, the resulting decrease in volumes from reduced drilling activities, and Midcoast Operating subsidiaries’ direct sale of their natural gas products to third parties instead of through the Logistics and Marketing segment.
(4) Represents calculation retrospectively reflecting the affiliate capitalization of MEP consisting of 4.1 million MEP Class A Common Units, 22.6 million MEP subordinated units and MEP general partner interest upon the transfer of a controlling ownership, including limited partner and general partner interest, in Midcoast Operating. The noncontrolling interest reflects the 61% that was retained by EEP through June 30, 2014. On July 1, 2014, we acquired an additional 12.6% interest in Midcoast Operating from EEP, decreasing EEP’s total ownership in Midcoast Operating to 48.4%.
(5) Our financial position and cash flow data include the effect of the following public limited partner unit issuances:

 

Date of Unit Issuance

   Class of Limited Partnership
Interest
     Number of Units Issued      Net Proceeds Including
General Partner Contribution
 
                   (in millions)  

December 2013

     Class A      2,775,000      $ 47.0  

November 2013

     Class A      18,500,000      $ 304.5  

 

    The 2013 equity issuances represent the Offering.

 

(6) Prior year amounts have been retrospectively adjusted upon adoption of ASU 2015-03, which requires presentation of debt issuance costs in the statement of financial position as a reduction to the carrying amount of Long-term debt, rather than as an asset. For further information, refer to Item 8. Financial Statements and Supplementary Data, Note 3. Changes in Accounting Policy.

 

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COMMON UNIT MARKET PRICE AND DISTRIBUTION INFORMATION

Common Unit Market Price Information

Class A Common Units trade on the NYSE under the symbol “MEP.” On January 26, 2017, the last trading day prior to the public announcement of the execution of the Merger Agreement, the reported closing price of Class A Common Units on the NYSE was $8.75 per share. On April 6, 2017, the most recent practicable date before the printing of this information statement, high and low reported sales prices of Class A Common Units were $8.05 and $8.00, respectively, and there were approximately 4,793 MEP Common Unitholders, including beneficial owners of common units held in “street name.”

The following table shows the high and low prices per common unit, as reported by the NYSE, for the periods indicated.

 

     Common Unit Price Ranges  
             High                      Low          

Period from April 1, 2017 to April 5, 2017

   $ 8.05      $ 7.95  

Quarter Ended March 31, 2017

   $ 9.00      $ 6.90  

Year Ended December 31, 2016

     

Quarter Ended December 31

   $ 9.07      $ 5.30  

Quarter Ended September 30

   $ 9.50      $ 6.79  

Quarter Ended June 30

   $ 9.89      $ 4.58  

Quarter Ended March 31

   $ 10.09      $ 3.76  

Year Ended December 31, 2015

     

Quarter Ended December 31

   $ 13.58      $ 6.50  

Quarter Ended September 30

   $ 13.36      $ 8.75  

Quarter Ended June 30

   $ 15.17      $ 10.27  

Quarter Ended March 31

   $ 16.00      $ 11.41  

Distribution Information

MEP considers cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. MEP’s ability to distribute available cash is contractually restricted by the terms of MEP’s credit facility. MEP’s credit facility contains covenants requiring MEP to maintain certain financial ratios. MEP is prohibited from making any distributions to unitholders if the distribution would cause an event of default, or an event of default exists, under its credit facility.

Under the terms of the MEP Merger Agreement, MEP is prohibited from paying distributions to its unitholders without the prior written consent of EECI except for distributions made in the ordinary course of business.

 

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The following table shows the cash distributions paid during each quarter of the year ended December 31, 2016 and the year ended December 31, 2015. Cash distributions shown below were paid within 50 days after the end of each applicable quarter.

 

     Cash Distribution
Paid Per Unit
 

Year Ended December 31, 2016

  

Quarter Ended December 31

   $ 0.3575  

Quarter Ended September 30

   $ 0.3575  

Quarter Ended June 30

   $ 0.3575  

Quarter Ended March 31

   $ 0.3575  

Year Ended December 31, 2015

  

Quarter Ended December 31

   $ 0.3575  

Quarter Ended September 30

   $ 0.3525  

Quarter Ended June 30

   $ 0.3475  

Quarter Ended March 31

   $ 0.3425  

 

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INFORMATION CONCERNING THE ENBRIDGE PARTIES AND MERGER SUB

As of December 31, 2016, Enbridge and its consolidated subsidiaries owned an effective 41.7% interest in EEP. EECI is an indirect wholly owned subsidiary of Enbridge and the general partner of EEP. EECI has delegated substantially all of its general partner authority to manage the business and affairs of EEP to EEM and owns 11.7% of the listed shares of EEM and all of the voting shares of EEM. EECI elects the members of the board of directors of EEM.

EEM is a publicly traded Delaware limited liability company that was formed on May 14, 2002. EEM is a limited partner of EEP through its ownership of i-units representing a special class of EEP’s limited partner interests. On October 17, 2002, pursuant to a delegation of control agreement with EECI, the general partner of EEP, EEM assumed the management of EEP’s business and affairs. EEM owns an approximate 16.6% ownership interest in EEP.

EEP is a publicly traded Delaware limited partnership that owns crude oil and liquid petroleum transportation and storage assets, and natural gas gathering, treating, processing, transportation and marketing assets in the United States. EEP was formed in 1991 by EECI, its general partner, to own and operate the Lakehead system, which is the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada, referred to as the Mainline system. A subsidiary of Enbridge owns the Canadian portion of the Mainline system. Enbridge is a leading provider of energy transportation, distribution and related services in North America and internationally. Enbridge is the ultimate parent of EECI. EEP is the sole owner of MEP GP, who is the general partner of MEP, and owns a 51.9% limited partner interest in MEP through its ownership of MEP common units. The principal business of EEP, EEM and EECI is to own, operate and develop a portfolio of pipelines and related midstream assets.

EECI formed Merger Sub on January 17, 2017 and is its sole member. Merger Sub was formed solely for the purpose of effecting the Merger. Merger Sub has not conducted any activities other than those incident to its formation and the matters contemplated by the Merger Agreement, including the preparation of applicable filings under the securities laws.

At the closing of the Merger, Merger Sub will merge with and into MEP, the separate existence of Merger Sub will cease and MEP will survive and continue to exist as a Delaware limited partnership.

Shares representing limited liability company interests in EEM trade on the NYSE under the symbol “EEQ.” Class A common units representing limited partner interests in EEP trade on the NYSE under the symbol “EEP.” The business address of EEM, EECI, EEP and Merger Sub is 1100 Louisiana St., Suite 3300, Houston, Texas 77002, and their phone number is (713) 821-2000.

During the past five years, none of the entities described above has been (1) convicted in a criminal proceeding or (2) party to any judicial or administrative proceeding (except for matters that were dismissed without sanction or settlement) that resulted in a judgment, decree or final order enjoining the entity from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.

 

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UNIT OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, DIRECTORS AND EXECUTIVE OFFICERS OF MEP AND THE ENBRIDGE PARTIES

MEP’s securities entitled to vote on the Merger Agreement and the Merger Transactions consist of the Class A Common Units and Class B common units. All of the Units (as defined in the MEP Partnership Agreement) may be voted by written consent. The unit ownership amounts below contain certain information about unitholders whom MEP believes are the “beneficial” owners of more than five percent (5%) of the outstanding Class A Common Units, as well as information regarding the MEP unit ownership by the directors and executive officers of MEP GP and the Enbridge Parties as of the dates listed below. Except as described below, MEP knows of no person that beneficially owns more than 5% of the outstanding Class A Common Units, based solely on filings made with the SEC.

The percentage of beneficial ownership is calculated on the basis of 22,610,056 Class A Common Units outstanding as of the dates listed below. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. The SEC has defined the “beneficial owner” of a security to include any person who, directly or indirectly, has or shares voting power and/or investment power over such security. In computing the number of the units beneficially owned by a person and the percentage ownership of that person, the units subject to options or other rights held by that person that are exercisable or will become exercisable within 60 days after the dates listed below, are deemed outstanding, while such units are not deemed outstanding for purposes of computing percentage ownership of any other person. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The percentages reflect beneficial ownership, as determined in accordance with Rule 13d-3 under the Exchange Act. The address for each director and executive officer of MEP, MEP GP, EEP and EECI is 1100 Louisiana St., Suite 3300, Houston, Texas 77002, except as otherwise noted.

Unit Ownership by MEP GP’s Directors and Executive Officers

The following table sets forth as of April 6, 2017, the number of Class A Common Units owned by each director and named executive officer of MEP GP.

 

Name of Beneficial Owner

   Class A Common
Units Beneficially
owned (1)(2)
     Percentage of Class
A Common Units
Beneficially Owned
 

Dan A. Westbrook(3)

     15,000        *  

John A. Crum

     12,000        *  

J. Herbert England

     5,000        *  

James G. Ivey

     10,000        *  

Mark A. Maki

     19,000        *  

R. Poe Reed(4)

     200        *  

Edmund P. Segner III

     12,000        *  

Stephen J. Neyland(5)

     8,270        *  

Kerry C. Puckett

     8,000        *  

All executive officers, directors, and nominees as a group (12 persons)

     97,470        *  

 

* Represents less than 1%.

 

(1) On January 26, 2017 MEP entered into the Merger Agreement with EECI whereby EECI will acquire all of our outstanding publicly held Class A Common Units. The transaction is expected to close during the second quarter of 2017, subject to customary conditions.
(2) Unless otherwise indicated, each beneficial owner has sole voting and investment power with respect to all of the Class A Common Units attributed to him or her.

 

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(3) Mr. Westbrook is the indirect owner of the units, which are held by the Westbrook Trust.
(4) Mr. Reed is the indirect owner of these units, of which 100 units each are held by his son and his daughter.
(5) The units beneficially owned by Mr. Neyland are held in a Family Trust for which Mr. Neyland is a co-trustee as well as a beneficiary.

Unit Ownership by EEP’s, EEM’s and EECI’s Directors and Executive Officers

As of April 6, 2017, EEM’s and EECI’s directors and executive officers beneficially owned and had the right to vote 47,270 Class A Common Units, which represents less than 1% of the MEP limited partner units entitled to vote. These 47,270 Class A Common Units are held by Mr. England, Mr. Maki, Mr. Neyland and Mr. Westbrook.

Unit Ownership by Enbridge’s Directors and Executive Officers

As of April 6, 2017, Enbridge’s directors and executive officers beneficially owned and had the right to vote 5,000 Class A Common Units, which represents less than 1% of the MEP limited partner units entitled to vote. These 5,000 Class A Common Units are held by Mr. England.

Unit Ownership of Other 5% or More Unitholders

The following table sets forth as of April 6, 2017, the number of MEP common units owned by each 5% or more unitholder:

 

Name of Beneficial Owner    Title of Class    Amount of
Units
Beneficially
owned
     Percentage of
Class
Beneficially
Owned
 

Enbridge Energy Partners, L.P.(1)

   Class A Common Units      1,335,056        5.9
   Class B common units      22,610,056        100

OppenheimerFunds Inc.(2)

   Class A Common Units      4,481,651        19.8

Oppenheimer SteelPath MLP Income Fund(3)

   Class A Common Units      3,100,729        13.7

Kayne Anderson Capital Advisors, L.P.(4)

   Class A Common Units      2,562,572        11.3

Clearbridge Investments, LLC(5)

   Class A Common Units      2,341,304        10.4

Atlantic Trust Group LLC(7)

   Class A Common Units      1,368,300        6.1

Oppenheimer SteelPath MLP Select 40 Fund(6)

   Class A Common Units      1,339,510        5.9

 

(1) As of February 15, 2017, EEP directly held (i) 1,335,056 Class A Common Units (ii) 22,610,056 MEP Class B common units and (iii) 922,859 General Partner units, which were held by MEP GP, a wholly owned subsidiary of EEP.
(2) OppenheimerFunds Inc. reported shared voting and dispositive power as to the 4,481,651 Class A Common Units in an amendment to its Schedule 13G, filed January 25, 2017.
(3) Oppenheimer SteelPath MLP Income Fund reported sole voting power and shared dispositive power as to the 3,100,729 Class A Common Units in an amendment to its Schedule 13G filed on January 25, 2017.
(4) Kayne Anderson Capital Advisors, L.P. reported shared voting and dispositive power as to the 2,562,572 Class A Common Units in an amendment to its schedule 13G, filed January 10, 2017.
(5) Clearbridge Investments, LLC reported sole voting and dispositive power as to the 2,341,304 Class A Common Units in an amendment to its schedule 13G, filed February 14, 2017.
(6) Oppenheimer SteelPath MLP Select 40 Fund reported sole voting power and shared dispositive power as to the 1,339,510 Class A Common Units in an amendment to its Schedule 13G filed on January 25, 2017.
(7) Atlantic Trust Group LLC reported sole voting and dispositive power as to the 1,368,300 Class A Common Units in its Schedule 13G, filed on February 13, 2017.

 

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CERTAIN PURCHASES AND SALES OF CLASS A COMMON UNITS

During the past 60 days, there have been no transactions in the Class A Common Units by MEP, MEP GP and the Enbridge Parties or any executive officer, director, associate or majority-owned subsidiary of the foregoing parties or by any pension, profit-sharing or similar plan of the foregoing parties.

DELISTING AND DEREGISTRATION OF CLASS A COMMON UNITS

If the Merger is completed, Class A Common Units will be delisted from the NYSE and deregistered under the Exchange Act (via termination of registration pursuant to Section 12(g) of the Exchange Act). After the closing of the Merger, MEP will also file a Form 15 to suspend its reporting obligations under Section 15(d) of the Exchange Act. As a result, MEP will no longer be obligated to file any periodic reports or other reports with the SEC on account of the Class A Common Units.

 

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WHERE YOU CAN FIND MORE INFORMATION

MEP files annual, quarterly and special reports and other information with the SEC. A copy of the annual report on Form 10-K for the year ended December 31, 2016 is attached as Annex D to this information statement. This report and other information filed by MEP with the Securities and Exchange Commission contain additional information about MEP. MEP will make these materials available for inspection and copying by any of its unitholders, or a representative of any unitholder who is so designated in writing, at its executive offices during regular business hours.

Because the Merger is a “going private” transaction, MEP, MEP GP and the Enbridge Parties have filed with the SEC a Transaction Statement on Schedule 13E-3 with respect to the proposed Merger. The Schedule 13E-3, including any amendments and exhibits filed or incorporated by reference as a part of it, is available for inspection as set forth above. The Schedule 13E-3 will be amended to report promptly any material changes in the information set forth in the most recent Schedule 13E-3 filed with the SEC with respect to the Merger and any such information contained in a document filed with the SEC after the date of this information statement will not automatically be incorporated into the Schedule 13E-3.

MEP will also make available on its website (http://www.midcoastpartners.com) under “Investor Relations” the annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed by MEP.

The opinion of Evercore and the presentations Evercore made to the MEP Committee will be made available for inspection and copying at the principal executive offices of MEP during regular business hours by any interested unitholder of MEP or such unitholder’s representative who has been so designated in writing.

The SEC maintains an Internet website that contains reports, proxy and information statements and other material that are filed through the SEC’s Electronic Data Gathering, Analysis and Retrieval (EDGAR) System. This system can be accessed at www.sec.gov. You can find information that MEP files with the SEC by reference to its name or to its SEC file number. You also may read and copy any document MEP files with the SEC at the SEC’s public reference room located at: 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information about the public reference room and its copy charges. MEP’s SEC filings are also available to the public through the New York Stock Exchange at 20 Broad Street, New York, New York 10005.

This information statement does not constitute an offer to sell, or a solicitation of an offer to buy, any securities, or the solicitation of a proxy, in any jurisdiction to or from any person to whom it is not lawful to make any offer or solicitation in that jurisdiction. The delivery of this information statement should not create an implication that there has been no change in the affairs of MEP since the date of this information statement or that the information herein is correct as of any later date regardless of the time of delivery of this information statement.

The provisions of the Merger Agreement are extensive and not easily summarized. You should carefully read the Merger Agreement in its entirety because it, and not this information statement, is the legal document that governs the Merger of MEP in which you own units.

The Merger Agreement contains representations and warranties by each of the parties to the Merger Agreement. These representations and warranties have been made solely for the benefit of the other parties to such Merger Agreement and:

 

    may be intended not as statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

 

    have been qualified by disclosures that were made to the other party in connection with the negotiation of the Merger, which disclosures are not reflected in the Merger Agreement;

 

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    may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors; and

 

    were made only as of the date of the Merger Agreement or such other date or dates as may be specified in the Merger Agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

This information statement is dated April 7, 2017. You should not assume that the information contained in this information statement is accurate as of any date other than that date, or that the information contained in the Form 10-K attached hereto as Annex D is accurate as of any date other than the date of the document attached hereto. Neither the mailing of the information statement to unitholders nor the issuance of the applicable Merger Consideration pursuant to the Merger will create any implication to the contrary.

 

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ANNEX A

Execution Version

 

 

AGREEMENT AND PLAN OF MERGER

DATED AS OF JANUARY 26, 2017

BY AND AMONG

ENBRIDGE ENERGY COMPANY, INC.,

ENBRIDGE HOLDINGS (LEATHER) L.L.C.,

MIDCOAST ENERGY PARTNERS, L.P.

AND

MIDCOAST HOLDINGS, L.L.C.

 

 

 

 

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TABLE OF CONTENTS

 

         Page  

ARTICLE I. DEFINED TERMS; CONSTRUCTION

     A-5  

Section 1.1

 

Definitions.

     A-5  

Section 1.2

 

Interpretation

     A-11  

ARTICLE II. THE MERGER

     A-12  

Section 2.1

 

The Merger and Surviving Entity

     A-12  

Section 2.2

 

Closing

     A-12  

Section 2.3

 

Effective Time

     A-12  

Section 2.4

 

Effects of the Merger

     A-13  

Section 2.5

 

Organizational Documents of the Surviving Entity

     A-13  

Section 2.6

 

Admission as Partner

     A-13  

ARTICLE III. MERGER CONSIDERATION; EXCHANGE PROCEDURES

     A-13  

Section 3.1

 

Merger Consideration

     A-13  

Section 3.2

 

Surrender of Class A Common Units

     A-14  

Section 3.3

 

Treatment of Partnership Incentive Awards; Termination of Partnership Equity Plan

     A-16  

Section 3.4

 

Adjustments

     A-16  

Section 3.5

 

No Dissenters’ Rights

     A-16  

ARTICLE IV. REPRESENTATIONS AND WARRANTIES OF THE PARTNERSHIP AND THE PARTNERSHIP GP

     A-17  

Section 4.1

 

Authority

     A-17  

Section 4.2

 

Capitalization.

     A-18  

Section 4.3

 

Governmental Approvals

     A-18  

Section 4.4

 

Legal Proceedings

     A-19  

Section 4.5

 

Opinion of Financial Advisor

     A-19  

Section 4.6

 

Brokers and Other Advisors

     A-19  

Section 4.7

 

Disclosure Letter

     A-19  

Section 4.8

 

No Other Representations or Warranties

     A-19  

ARTICLE V. REPRESENTATIONS AND WARRANTIES OF PARENT AND MERGER SUB

     A-20  

Section 5.1

 

Organization, Standing and Corporate Power

     A-20  

Section 5.2

 

Operations and Ownership of Merger Sub

     A-20  

Section 5.3

 

Ownership of Partnership Units

     A-20  

Section 5.4

 

Authority; Noncontravention

     A-20  

Section 5.5

 

Governmental Approvals

     A-21  

Section 5.6

 

Legal Proceedings

     A-21  

Section 5.7

 

Access to Information

     A-22  

Section 5.8

 

Information Supplied

     A-22  

Section 5.9

 

Brokers and Other Advisors

     A-22  

Section 5.10

 

Available Funds

     A-22  

Section 5.11

 

Disclosure Letter

     A-22  

Section 5.12

 

No Other Representations or Warranties

     A-22  

 

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         Page  

ARTICLE VI. ADDITIONAL COVENANTS AND AGREEMENTS

     A-23  

Section 6.1

 

Preparation of the Partnership Information Statement and Schedule 13E-3

     A-23  

Section 6.2

 

Conduct of Business

     A-24  

Section 6.3

 

Partnership Adverse Recommendation Change

     A-25  

Section 6.4

 

Consummation of the Merger.

     A-27  

Section 6.5

 

Public Announcements

     A-28  

Section 6.6

 

Access to Information

     A-28  

Section 6.7

 

Indemnification and Insurance

     A-28  

Section 6.8

 

Fees and Expenses

     A-29  

Section 6.9

 

Section 16 Matters

     A-29  

Section 6.10

 

Termination of Trading and Deregistration

     A-30  

Section 6.11

 

GP Conflicts Committee

     A-30  

Section 6.12

 

Performance by the Partnership GP

     A-30  

Section 6.13

 

Takeover Statutes

     A-30  

Section 6.14

 

No Rights Triggered

     A-30  

Section 6.15

 

Notification of Certain Matters

     A-30  

Section 6.16

 

Transaction Litigation

     A-30  

Section 6.17

 

Distributions.

     A-31  

Section 6.18

 

Tax Matters.

     A-31  

ARTICLE VII. CONDITIONS PRECEDENT

     A-31  

Section 7.1

 

Conditions to Each Party’s Obligation to Effect the Merger

     A-31  

Section 7.2

 

Conditions to Obligations of Parent and Merger Sub to Effect the Merger

     A-31  

Section 7.3

 

Conditions to Obligation of the Partnership to Effect the Merger

     A-32  

Section 7.4

 

Frustration of Closing Conditions

     A-32  

ARTICLE VIII. TERMINATION

     A-32  

Section 8.1

 

Termination

     A-32  

Section 8.2

 

Effect of Termination

     A-33  

ARTICLE IX. MISCELLANEOUS

     A-34  

Section 9.1

 

No Survival, Etc.

     A-34  

Section 9.2

 

Amendment or Supplement

     A-34  

Section 9.3

 

Extension of Time, Waiver, Etc

     A-34  

Section 9.4

 

Assignment

     A-35  

Section 9.5

 

Counterparts

     A-35  

Section 9.6

 

Entire Understanding; No Third-Party Beneficiaries

     A-35  

Section 9.7

 

Governing Law; Jurisdiction; Waiver of Jury Trial

     A-35  

Section 9.8

 

Specific Performance

     A-36  

Section 9.9

 

Notices

     A-36  

Section 9.10

 

Severability

     A-38  

Section 9.11

 

Non-Recourse

     A-38  

 

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AGREEMENT AND PLAN OF MERGER

This AGREEMENT AND PLAN OF MERGER, dated as of January 26, 2017 (this “Agreement”), is by and among Enbridge Energy Company, Inc., a Delaware corporation (“Parent”), Enbridge Holdings (Leather) L.L.C., a Delaware limited liability company and wholly-owned Subsidiary of Parent (“Merger Sub”), Midcoast Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), and Midcoast Holdings, L.L.C., a Delaware limited liability company and the general partner of the Partnership (the “Partnership GP”). Certain capitalized terms used in this Agreement are defined in Article I.

W I T N E S S E T H:

WHEREAS, the Conflicts Committee of the Board of Directors of the Partnership GP (the “GP Conflicts Committee”) has (i) determined that each of the Merger, this Agreement and the transactions contemplated hereby is fair and reasonable to and in the best interests of the Partnership Group and the Partnership Unaffiliated Unitholders, (ii) approved this Agreement and the transactions contemplated hereby, including the Merger and the issuance of the New Class A Common Units, (iii) recommended that the Board of Directors of the Partnership GP (the “GP Board”) approve this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger and the issuance of the New Class A Common Units, and (iv) recommended that the GP Board submit this Agreement to a vote of the Limited Partners and recommend approval of this Agreement, including the Merger, by the Limited Partners;

WHEREAS, the GP Board (acting based in part upon the recommendation of the GP Conflicts Committee) has (i) determined that each of the Merger, this Agreement and the transactions contemplated hereby is fair and reasonable to and in the best interests of the Partnership Group and the Limited Partners, (ii) approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger and the issuance of the New Class A Common Units, (iii) resolved to submit this Agreement to a vote of the Limited Partners by written consent, and (iv) recommended approval of this Agreement, including the Merger, by the Limited Partners;

WHEREAS, the Special Committee of the Board of Directors of the EEP GP Delegate (the “EEP GP Delegate Conflicts Committee”) has (i) determined based upon the facts and circumstances it deemed relevant, reasonable or appropriate to its decision, including its review of the terms of the Merger and the transactions contemplated thereby, including the Merger Agreement and the Support Agreement (in substantially the forms previously provided to the Committee), the advice of its legal and financial advisers and the fairness opinion dated January 26, 2017, of Simmons & Company International received by the Committee, that the Merger and the transactions contemplated thereby is fair and reasonable to, and in the best interests of, Enbridge Energy Partners, L.P., a Delaware limited partnership (“EEP”), including the EEP Unaffiliated Unitholders, (ii) recommended that the Board of Directors of the EEP GP Delegate (the “EEP GP Delegate Board”) cause EEP to (A) exercise EEP’s power, as the sole member of MEP GP, to approve the Merger and the transactions contemplated thereby, including the adoption and approval of the Merger Agreement and the Support Agreement, (ii) vote or deliver a written consent in respect of EEP’s limited partner interests in MEP in favor of the Merger and the transactions contemplated thereby and (iii) enter into the Support Agreement;

WHEREAS, the EEP GP Delegate Board (acting in part based upon the recommendation of the EEP GP Delegate Conflicts Committee) has (i) determined that each of the Merger, this Agreement and the transactions contemplated hereby is fair and reasonable to and in the best interests of EEP, including its partners, (ii) authorized and approved the voting or consent by EEP, (A) as the sole member of Partnership GP and (B) of the Units held by EEP, in favor of the Merger and the adoption and approval of this Agreement, and (iii) authorized and approved the EEP Support Agreement;

WHEREAS, EEP, as the sole member of the Partnership GP, has approved the adoption of this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger;

 

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WHEREAS, the Board of Directors of Parent (the “Parent Board”) has (i) determined that the Merger is in the best interests of Parent and EEP, and declared it advisable to enter into this Agreement and (ii) approved the adoption of this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger; and

WHEREAS, Parent, as the sole member of Merger Sub, has (i) determined that the Merger is in the best interests of Merger Sub, and declared it advisable to enter into this Agreement and (ii) approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger.

NOW, THEREFORE, in consideration of the representations, warranties, covenants and agreements contained in this Agreement, and intending to be legally bound, the parties agree as follows:

ARTICLE I.

DEFINED TERMS; CONSTRUCTION

Section 1.1 Definitions.

(a) As used in this Agreement, the following terms have the meanings ascribed thereto below:

Acquisition Proposal” means any inquiry, proposal or offer from or by any Person other than Parent, Merger Sub or their Affiliates relating to: (a) any direct or indirect acquisition (whether in a single transaction or series of related transactions) of (i) more than 15% of the assets of the Partnership and its Subsidiaries, taken as a whole, (ii) more than 15% of the outstanding equity securities of the Partnership or (iii) a business or businesses that constitute more than 15% of the cash flow, net revenues or net income of the Partnership and its Subsidiaries, taken as a whole; (b) any tender offer or exchange offer, as defined under the Exchange Act, that, if consummated, would result in any Person or “group” (as defined in Section 13(d) of the Exchange Act) beneficially owning more than 15% of the outstanding equity securities of the Partnership; or (c) any merger, consolidation, business combination, recapitalization, liquidation, dissolution or similar transaction involving the Partnership or any of its Subsidiaries, other than the Merger.

Affiliate” means, as to any Person, any other Person that, directly or indirectly, controls, or is controlled by, or is under common control with, such Person. For this purpose, “control” (including, with its correlative meanings, “controlled by” and “under common control with”) means the possession, directly or indirectly, of the power to direct or cause the direction of management or policies of a Person, whether through the ownership of securities or partnership or other ownership interests, by contract or otherwise; provided, however, that, except where otherwise expressly provided, for the purposes of this Agreement, (a) the Partnership, the Partnership GP and their Subsidiaries shall not be considered Affiliates of Parent or any of its Subsidiaries, and (b) EEP shall be deemed to be an Affiliate of Parent and its Subsidiaries and shall not be considered an Affiliate of the Partnership, the Partnership GP or any of their Subsidiaries.

Agreement” has the meaning set forth in the Preamble.

Antitrust Laws” means the Sherman Act of 1890, as amended, the Clayton Antitrust Act of 1914, as amended, the HSR Act, the Federal Trade Commission Act of 1914, as amended, in each case including the rules and regulations promulgated thereunder, and all other applicable Laws issued by a Governmental Authority that are designed or intended to prohibit, restrict or regulate actions having the purpose or effect of monopolization or restraint of trade or lessening of competition.

Book-Entry Units” has the meaning set forth in Section 3.1(a).

 

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Business Day” means a day except a Saturday, a Sunday or other day on which the SEC or banks in the cities of Houston or New York are authorized or required by applicable Law to be closed.

Certificate of Merger” has the meaning set forth in Section 2.3.

Certificated Units” has the meaning set forth in Section 3.1(a).

Class A Common Unit” has the meaning set forth in the Partnership Agreement.

Class B Common Unit” has the meaning set forth in the Partnership Agreement.

Closing” has the meaning set forth in Section 2.2.

Closing Date” has the meaning set forth in Section 2.2.

Code” has the meaning set forth in Section 3.2(h).

Common Unit” has the meaning set forth in the Partnership Agreement.

Confidentiality Agreement” means a confidentiality agreement of the nature generally used in circumstances similar to those contemplated in Section 6.3, as determined by the Partnership in its reasonable business judgment; provided, however, that such Confidentiality Agreement shall (a) have a term of not less than one year, (b) provide that all non-public information pertaining to the Partnership and/or Parent be protected as confidential information thereunder, subject to customary exceptions, and (c) provide that Parent is a third-party beneficiary with respect to any breach thereof relating to information relating to Parent.

Contract” means any contract, purchase order, license, sublicense, lease, sublease, franchise, warranty, option, warrant, guaranty, indenture, note, bond, mortgage or other legally binding agreement, instrument or obligation, whether written or unwritten.

DLLCA” means the Delaware Limited Liability Company Act.

DRULPA” means the Delaware Revised Uniform Limited Partnership Act.

EEP” has the meaning set forth in the Recitals.

EEP GP Delegate” means Enbridge Energy Management, L.L.C., as delegate of Parent, the general partner of EEP.

EEP GP Delegate Board” has the meaning set forth in the Recitals.

EEP GP Delegate Conflicts Committee” has the meaning set forth in the Recitals.

EEP Support Agreement” means the Support Agreement of EEP, in the form attached hereto as Exhibit A.

EEP Unaffiliated Unitholders” means the holders of units of limited partner interest in EEP other than Parent, Enbridge Energy Management, L.L.C. and their respective Affiliates.

Effective Time” has the meaning set forth in Section 2.3.

Enbridge” means Enbridge Inc., a Canadian corporation.

 

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Exchange Act” means the Securities Exchange Act of 1934, as amended and the rules and regulations promulgated thereunder.

Exchange Fund” has the meaning set forth in Section 3.2(b).

Fourth Quarter Distribution” has the meaning set forth in Section 6.17.

GAAP” means generally accepted accounting principles in the United States.

General Partner Interest” has the meaning set forth in the Partnership Agreement.

General Partner Unit” has the meaning set forth in the Partnership Agreement.

Governmental Authority” means any government, court, arbitrator, regulatory or administrative agency, commission or authority or other governmental instrumentality, whether federal, state, local, tribal, domestic, foreign or multinational.

GP Board” has the meaning set forth in the Recitals.

GP Conflicts Committee” has the meaning set forth in the Recitals.

HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations promulgated thereunder.

Incentive Distribution Right” has the meaning set forth in the Partnership Agreement.

Indemnified Person” means any Person who is now, or has been or becomes at any time prior to the Effective Time, an officer, director or employee of the Partnership or any of its Subsidiaries or the Partnership GP and also with respect to any such Person, in their capacity as a director, officer, employee, member, trustee or fiduciary of another corporation, foundation, partnership, joint venture, trust, pension or other employee benefit plan or enterprise (whether or not such other entity or enterprise is affiliated with the Partnership) serving at the request of or on behalf of the Partnership or the Partnership GP or any of their respective Subsidiaries and together with such Person’s heirs, executors or administrators.

Knowledge” means, with respect to Parent, the actual knowledge of the Persons listed in Section 1.1 of the Parent Disclosure Letter, or, with respect to the Partnership, the actual knowledge of the Persons listed in Section 1.1 of the Partnership Disclosure Letter, in each case after reasonable investigation.

Laws” means any law, statute, constitution, fundamental principle of common law, ordinance, rule, regulation, code, injunction, order, judgment, settlement, ruling, decree, directive, code, writ, binding case law, governmental guideline or interpretation having the force of law or legally enforceable requirement issued, enacted, adopted, promulgated, implemented or otherwise put in effect by or under the authority of any Governmental Authority.

Liens” means any pledge, lien, charge, mortgage, encumbrance, option, right of first refusal or other preferential purchase right, adverse claim and interest, or security interest of any kind or nature whatsoever (including any restriction on the right to vote or transfer the same, except for such transfer restrictions of general applicability as may be provided under the Securities Act, the “blue sky” Laws of the various States of the United States or similar Law of other applicable jurisdictions).

Limited Partner” has the meaning set forth in the Partnership Agreement.

 

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Material Adverse Effect” means, with respect to either Parent or the Partnership, any change, effect, event or occurrence that, individually or in the aggregate, (x) is or would reasonably be expected to be material and adverse to the financial position, results of operations, business or assets of the Parent and its Subsidiaries taken as a whole, or the Partnership and its Subsidiaries taken as a whole, respectively, or (y) materially impairs or delays, or could reasonably be expected to materially impair or delay, the ability of Parent or the Partnership, respectively, to perform its obligations under this Agreement or otherwise materially threaten or materially impede the consummation of the Merger and the other transactions contemplated by this Agreement; provided, however, that Material Adverse Effect shall not be deemed to include any of the following or the impact thereof: (a) circumstances affecting the gathering, processing treating, transportation and marketing of natural gas, natural gas liquids, crude oil and condensate industry generally (including the price of natural gas, natural gas liquids, crude oil and condensate and the costs associated with the gathering, processing treating, transportation and marketing thereof), in any region in which Parent or the Partnership, respectively, operates, (b) any general market, economic, financial or political conditions, or outbreak of hostilities or war, in the United States of America or elsewhere, (c) changes in Law, (d) earthquakes, hurricanes, floods, or other natural disasters, (e) any failure of Parent or the Partnership, respectively, to meet any internal or external projections, forecasts or estimates of revenue, cash flows or earnings for any period (but not the underlying causes of any such failure), (f) changes in the market price or trading volume of Class A Common Units (but not any effect underlying any decrease that would otherwise constitute a Material Adverse Effect), or (g) the announcement or pendency of this Agreement or the matters contemplated hereby or the compliance by any party with the provisions of this Agreement; provided, that, in the case of clause (a), (b) or (c), the impact on Parent or the Partnership, respectively, is not disproportionately adverse as compared to others in the industry referred to in clause (a) of this definition generally.

Material Contract” means any Contract that would be required to be filed by the Partnership as a “material contract” pursuant to Item 601(b)(10) of Regulation S-K under the Securities Act.

Maximum Amount” has the meaning set forth in Section 6.7(b).

Merger” has the meaning set forth in Section 2.1.

Merger Consideration” has the meaning set forth in Section 3.1(a).

Merger Sub” has the meaning set forth in the Preamble.

New Class A Common Units” has the meaning set forth in Section 3.1(b).

Notice of Proposed Adverse Recommendation Change” has the meaning set forth in Section 6.3(c)(i).

NYSE” means the New York Stock Exchange.

Organizational Documents” means any charter, certificate of incorporation, articles of association, bylaws, partnership agreement, operating agreement or similar formation or governing documents and instruments.

Outside Date” has the meaning set forth in Section 8.1(b)(i).

Parent” has the meaning set forth in the Preamble.

Parent Board” has the meaning set forth in the Recitals.

Parent Disclosure Letter” means the letter delivered by Parent setting forth, among other things, items the disclosure of which is necessary or appropriate in relation to any or all of their respective representations and warranties.

 

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Parent Organizational Documents” has the meaning set forth in Section 5.1.

Partnership” has the meaning set forth in the Preamble.

Partnership Adverse Recommendation Change” has the meaning set forth in Section 6.3(b).

Partnership Agreement” means the First Amended and Restated Agreement of Limited Partnership of the Partnership, dated as of November 13, 2013, as amended, modified or supplemented from time to time.

Partnership Board Recommendation” has the meaning set forth in Section 6.1(b).

Partnership Disclosure Letter” has the meaning set forth in Section 4.7.

Partnership Fairness Opinion” has the meaning set forth in Section 4.5.

Partnership Financial Advisor” has the meaning set forth in Section 4.5.

Partnership GP” has the meaning set forth in the Preamble.

Partnership GP LLC Agreement” means the First Amended and Restated Limited Liability Company Agreement of the Partnership GP, dated as of November 6, 2013, as amended, modified or supplemented from time to time.

Partnership Group” has the meaning set forth in the Partnership Agreement.

Partnership Incentive Plan Adjustment” has the meaning set forth in Section 3.3(a).

Partnership Information Statement” means the information statement to be filed by the Partnership in connection with the Merger.

Partnership Interest” has the meaning set forth in the Partnership Agreement.

Partnership Long-Term Incentive Plan” means the Partnership Long-Term Incentive Plan, dated October 10, 2013, as amended from time to time and including any successor or replacement plan or plans.

Partnership Material Adverse Effect” has the meaning set forth in Section 4.1(b).

Partnership Notice Period” has the meaning set forth in Section 6.3(c)(i).

Partnership SEC Documents” means the reports, schedules, forms, certifications, prospectuses, and registration, proxy and other statements required to be filed or furnished by them with the SEC since December 31, 2012 (collectively and together with all documents filed or publicly furnished on a voluntary basis on Form 8-K, and in each case including all required exhibits and schedules thereto and documents incorporated by reference therein.

Partnership Unaffiliated Unitholders” means holders of Units other than Parent, EEP, Partnership GP and their respective Affiliates.

Partnership Unitholder Approval” has the meaning set forth in Section 7.1(a).

Paying Agent” has the meaning set forth in Section 3.2(a).

 

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Permit” means all franchises, licenses, certificates, determinations, permits, and other authorizations, approvals, waivers, registrations, consents, orders and approvals from any Governmental Authority.

Person” means an individual, a corporation, a limited liability company, a partnership, an association, a trust or any other entity, including a Governmental Authority.

Proceeding” means any actual or threatened claim (including a claim of a violation of Law), action, audit, demand, suit, proceeding, investigation or other proceeding at law or in equity or order or ruling, in each case whether civil, criminal, administrative, investigative or otherwise and whether or not such claim, action, audit, demand, suit, proceeding, investigation or other proceeding or order or ruling results in a formal civil or criminal litigation or regulatory action.

Receiving Party” has the meaning set forth in Section 6.3(a).

Representatives” has the meaning set forth in Section 6.3(a).

Restraints” has the meaning set forth in Section 7.1(b).

Rights” means, with respect to any Person, (a) options, warrants, preemptive rights, subscriptions, calls or other rights, convertible securities, exchangeable securities, agreements or commitments of any character obligating such Person (or the general partner of such Person) to issue, transfer or sell any partnership interest or other equity interest of such Person or any of its Subsidiaries or any securities convertible into or exchangeable for such partnership interests or equity interests, or (b) contractual obligations of such Person (or the general partner of such Person) to repurchase, redeem or otherwise acquire any partnership interest or other equity interest in such Person or any of its Subsidiaries or any such securities or agreements listed in clause (a) of this definition.

Schedule 13E-3” means a Rule 13e-3 transaction statement on Schedule 13E-3 relating to the Partnership Unitholder Approval and the transactions contemplated hereby, as amended or supplemented.

SEC” means the United States Securities and Exchange Commission.

Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations thereunder.

Subordinated Unit” has the meaning set forth in the Partnership Agreement.

Subsidiary” when used with respect to any Person, means any Person of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power (or, in the case of a partnership, more than 50% of the general partner interests or, in the case of a limited liability company, the managing member) are, as of such date, owned by such Person or one or more Subsidiaries of such Person or by such Person and one or more Subsidiaries of such party; provided, however, that, except where otherwise expressly provided, for the purposes of this Agreement, the Partnership, the Partnership GP and their Subsidiaries shall not be considered Subsidiaries of Parent or EEP.

Superior Proposal” shall mean any bona fide written Acquisition Proposal (except that reference to 15% within the definition of “Acquisition Proposal” shall be replaced by 50%) made by a third party after the date of this Agreement and not in breach of Section 6.3 and on terms that the GP Board determines, in its good faith judgment and after consulting with its or the Partnership’s financial advisors and outside legal counsel and the GP Conflicts Committee, and taking into account the financial, legal, regulatory and other aspects of the Acquisition Proposal (including any conditions to and the expected timing of consummation and any risks of non-consummation), (i) to be more favorable to the Partnership Unaffiliated Unitholders, from a financial point of view, than the Merger (taking into account the transactions contemplated by this Agreement and any revised

 

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proposal by Parent to amend the terms of this Agreement made in accordance with Section 6.3(c)) and (ii) is reasonably likely to be consummated and, if a cash transaction in whole or in part, has financing that is fully committed or reasonably determined to be available by the GP Board after consulting with the GP Conflicts Committee.

Surviving Entity” has the meaning set forth in Section 2.1.

Takeover Statutes” means any “fair price,” “moratorium,” “control share acquisition,” “business combination” or any other anti-takeover statute or similar statute enacted under state or federal law, and any similar provision incorporated into an Organizational Document.

Tax” or “Taxes” means any and all U.S. federal, state or local or non-U.S. or provincial taxes, charges, imposts, levies or other assessments, including all net income, gross receipts, capital, sales, use, ad valorem, value added, transfer, franchise, profits, inventory, capital stock, license, withholding, payroll, employment, social security, unemployment, excise, severance, stamp, occupation, property and estimated taxes, customs duties, fees, assessments and similar charges, including any and all interest, penalties, fines, additions to tax or additional amounts imposed by any Governmental Authority in connection or with respect thereto.

Tax Return” means any return, report or similar filing (including any attached schedules, supplements and additional or supporting material) filed or required to be filed with respect to Taxes, including any information return, claim for refund, amended return or declaration of estimated Taxes (and including any amendments with respect thereto).

Unit” has the meaning set forth in the Partnership Agreement.

Unit Majority” has the meaning set forth in the Partnership Agreement.

Section 1.2 Interpretation. Unless expressly provided for elsewhere in this Agreement, this Agreement will be interpreted in accordance with the following provisions:

(a) the words “this Agreement,” “herein,” “hereby,” “hereunder,” “hereof,” and other equivalent words refer to this Agreement as an entirety and not solely to the particular portion, article, section, subsection or other subdivision of this Agreement in which any such word is used;

(b) examples are not to be construed to limit, expressly or by implication, the matter they illustrate;

(c) the word “including” and its derivatives means “including without limitation” and is a term of illustration and not of limitation;

(d) all definitions set forth herein are deemed applicable whether the words defined are used herein in the singular or in the plural and correlative forms of defined terms have corresponding meanings;

(e) the word “or” is not exclusive and has the inclusive meaning represented by the phrase “and/or”;

(f) a defined term has its defined meaning throughout this Agreement and each exhibit to this Agreement, regardless of whether it appears before or after the place where it is defined;

(g) all references to prices, values or monetary amounts refer to United States dollars;

(h) wherever used herein, any pronoun or pronouns will be deemed to include both the singular and plural and to cover all genders;

 

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(i) this Agreement has been jointly prepared by the parties, and this Agreement will not be construed against any Person as the principal draftsperson of this Agreement or thereof and no consideration may be given to any fact or presumption that any party had a greater or lesser hand in drafting this Agreement;

(j) each covenant, term and provision of this Agreement will be construed simply according to its fair meaning; prior drafts of this Agreement or the fact that any clauses have been added, deleted or otherwise modified from any prior drafts of this Agreement will not be used as an aid of construction or otherwise constitute evidence of the intent of the parties and no presumption or burden of proof will arise favoring or disfavoring any party hereto by virtue of such prior drafts;

(k) the captions of the articles, sections or subsections appearing in this Agreement are inserted only as a matter of convenience and in no way define, limit, construe or describe the scope or extent of such section, or in any way affect this Agreement;

(l) any references herein to a particular Section or Article means a Section or Article of this Agreement unless otherwise expressly stated herein;

(m) the Parent Disclosure Letter and the Partnership Disclosure Letter are incorporated herein by reference and will be considered part of this Agreement;

(n) unless otherwise specified herein, all accounting terms used herein will be interpreted, and all determinations with respect to accounting matters hereunder will be made, in accordance with GAAP, applied on a consistent basis;

(o) all references to days mean calendar days unless otherwise provided; and

(p) all references to time mean Houston, Texas time.

ARTICLE II.

THE MERGER

Section 2.1 The Merger and Surviving Entity. Upon the terms and subject to the conditions of this Agreement, and in accordance with the DRULPA and the DLLCA, at the Effective Time, Merger Sub shall merge with and into the Partnership (the “Merger”), the separate existence of Merger Sub will cease and the Partnership shall survive and continue to exist as a Delaware limited partnership (the Partnership as the surviving entity in the Merger, sometimes being referred to herein as the “Surviving Entity”).

Section 2.2 Closing. Subject to the provisions of Article VII, the closing of the Merger (the “Closing”) shall take place at the offices of Latham & Watkins LLP, 811 Main Street, Suite 3700, Houston, Texas 77002 at 10:00 A.M., Houston, Texas time, on the third Business Day after the satisfaction or waiver of the conditions set forth in Article VII (other than conditions that by their nature are to be satisfied at the Closing, but subject to the satisfaction or waiver of those conditions), or at such other place, date and time as the Partnership and Parent shall agree. The date on which the Closing actually occurs is referred to as the “Closing Date.”

Section 2.3 Effective Time. Subject to the provisions of this Agreement, at the Closing, the Partnership will cause a certificate of merger substantially in the form attached hereto as Exhibit B, executed in accordance with the relevant provisions of the Partnership Agreement, the DRULPA and the DLLCA (the “Certificate of Merger”), to be duly filed with the Secretary of State of the State of Delaware. The Merger will become effective at such time as the Certificate of Merger has been duly filed with the Secretary of State of the State of Delaware or at such later date or time as may be agreed by the Partnership and Parent in writing and specified in the Certificate of Merger (the effective time of the Merger being hereinafter referred to as the “Effective Time”).

 

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Section 2.4 Effects of the Merger. The Merger shall have the effects set forth in this Agreement, the Partnership Agreement and the applicable provisions of the DRULPA and the DLLCA. Without limiting the generality of the foregoing and subject thereto, at the Effective Time, all the property, rights, privileges, powers and franchises and all and every other interest of the Partnership shall continue in the Partnership as the Surviving Entity, all the property, rights, privileges, powers and franchises and all and every other interest of Merger Sub shall vest in the Partnership as the Surviving Entity, all claims, obligations, debts, liabilities and duties of the Partnership shall continue in the Partnership as the Surviving Entity and all claims, obligations, debts, liabilities and duties of Merger Sub shall become the claims, obligations, debts, liabilities and duties of the Partnership as the Surviving Entity.

Section 2.5 Organizational Documents of the Surviving Entity. At the Effective Time, (a) the certificate of limited partnership of the Partnership as in effect immediately prior to the Effective Time shall remain unchanged and shall be the certificate of limited partnership of the Surviving Entity from and after the Effective Time, until duly amended in accordance with applicable Law and (b) the Partnership Agreement as in effect immediately prior to the Effective Time shall remain unchanged and shall be the agreement of limited partnership of the Surviving Entity from and after the Effective Time, until duly amended in accordance with the terms thereof and applicable Law.

Section 2.6 Admission as Partner. At the Effective Time, (a) by virtue of the Merger, notwithstanding anything to the contrary in the Partnership Agreement, Parent is hereby admitted as a limited partner of the Partnership and shall be registered as such on the books of the Partnership, (b) by virtue of the Merger, Parent and EEP will hold all limited partner interests in the Partnership, (c) Partnership GP shall continue as the sole general partner of the Partnership and (d) the Partnership shall continue without dissolution.

ARTICLE III.

MERGER CONSIDERATION; EXCHANGE PROCEDURES

Section 3.1 Merger Consideration. Subject to the provisions of this Agreement, at the Effective Time, by virtue of the Merger and without any action on the part of Parent, Merger Sub, the Partnership, the Partnership GP or any holder of Parent securities or Partnership securities:

(a) Conversion of Class A Common Units. Subject to Sections 3.1(d) and (f) and Section 3.4, each Class A Common Unit issued and outstanding as of immediately prior to the Effective Time shall be converted into the right to receive $8.00 per Class A Common Unit in cash without any interest thereon (the “Merger Consideration”). As of the Effective Time, all Class A Common Units converted into the right to receive the Merger Consideration pursuant to this Section 3.1(a) shall no longer be outstanding and shall automatically be canceled and cease to exist. As of the Effective Time, each holder of a certificate that immediately prior to the Effective Time represented any such Class A Common Units (“Certificated Units”) or non-certificated Class A Common Units represented in book-entry form immediately prior to the Effective Time (“Book-Entry Units”) shall cease to have any rights with respect thereto, except the right to receive the Merger Consideration to be issued or paid in consideration therefor upon surrender of such Certificated Unit or Book-Entry Unit in accordance with Section 3.2(c), without interest.

(b) Issuance of Class A Common Units to Parent. The limited liability company interests in Merger Sub issued and outstanding immediately prior to the Effective Time shall be converted into the number of Class A Common Units of the Surviving Entity equal to the number of Class A Common Units converted into the right to receive the Merger Consideration pursuant to Section 3.1(a) (the “New Class A Common Units”).

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Common Units are converted into the right to receive the Merger Consideration pursuant to this Section 3.1 shall cease to be limited partners of the Partnership pursuant to this Agreement and that, immediately following the Effective Time, Parent and EEP are the only limited partners of the Partnership.

(d) Treatment of Partnership Owned Units and Parent Owned Partnership Interests. Any Partnership Interests (other than the General Partner Interest, the Units owned by EEP and the Incentive Distribution Rights) that are owned immediately prior to the Effective Time by the Partnership or any Subsidiary of the Partnership, and any Partnership Interests (other than the General Partner Interest, the Units owned by EEP and the Incentive Distribution Rights) owned immediately prior to the Effective Time by Parent or any Affiliate of Parent will be automatically cancelled and will cease to exist. No consideration will be delivered in exchange for such cancelled Partnership Interests.

(e) General Partner Interest Unaffected. The General Partner Interest issued and outstanding as of immediately prior to the Effective Time shall be unaffected by the Merger and shall remain outstanding.

(f) Treatment of Incentive Distribution Rights and EEP Owned Units.

(i) The Incentive Distribution Rights issued and outstanding as of immediately prior to the Effective Time, which are owned by the Partnership GP, shall be unchanged and remain issued and outstanding in the Surviving Entity, and no consideration shall be delivered in respect thereof.

(ii) The Units issued and outstanding and owned by EEP as of immediately prior to the Effective Time shall be unchanged and remain issued and outstanding in the Surviving Entity, and no consideration shall be delivered in respect thereof.

(g) Distributions. To the extent applicable, holders of Units immediately prior to the Effective Time shall have continued rights to any distribution, without interest, with respect to such Units with a record date occurring prior to the Effective Time that has been declared by the Partnership GP with respect to such Units in accordance with the terms of this Agreement and which remains unpaid as of the Effective Time. Such distributions by the Partnership are not part of the Merger Consideration and shall be paid on the payment date set therefor to such holders (or former holders) of Units, as applicable. To the extent applicable, holders of Units prior to the Effective Time (other than EEP) shall have no rights to any distribution with respect to such Units with a record date occurring on or after the Effective Time that may have been declared by the Partnership GP with respect to such Units prior to the Effective Time and which remains unpaid as of the Effective Time.

Section 3.2 Surrender of Class A Common Units.

(a) Paying Agent. Prior to the Closing Date, Parent shall appoint a paying agent reasonably acceptable to the Partnership (the “Paying Agent”) for the purpose of exchanging Certificated Units and Book-Entry Units for the Merger Consideration. As promptly as practicable after the Effective Time, Parent will send, or will cause the Paying Agent to send, to each holder of record of Class A Common Units as of the Effective Time whose Class A Common Units were converted into the right to receive the Merger Consideration, a letter of transmittal (which shall specify that, with respect to Certificated Units, the delivery shall be effected, and risk of loss and title shall pass, only upon proper delivery of the Certificated Unit (or an affidavit of loss in lieu thereof pursuant to Section 3.2(g)) to the Paying Agent) in such customary forms as the Partnership and Parent may reasonably agree, including, as applicable, instructions for use in effecting the surrender of Certificated Units (or effective affidavits of loss in lieu thereof pursuant to Section 3.2(g)) and Book-Entry Units to the Paying Agent in exchange for the Merger Consideration.

(b) Deposit. On or prior to the Closing Date, Parent shall deposit or cause to be deposited with the Paying Agent, in trust for the benefit of the holders of Class A Common Units as of the Effective Time whose Class A Common Units were converted into the right to receive the Merger Consideration, an amount of cash equal to the amount of the aggregate Merger Consideration payable pursuant to Section 3.1(a) and upon the due surrender of

 

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the Certificated Units (or affidavits of loss in lieu thereof pursuant to Section 3.2(g) with respect to Certificated Units) or Book-Entry Units pursuant to the provisions of this Article III. All such cash deposited with the Paying Agent shall be referred to in this Agreement as the “Exchange Fund.” The Paying Agent shall, pursuant to irrevocable instructions delivered by Parent at or prior to the Effective Time, deliver the Merger Consideration contemplated to be paid pursuant to this Article III out of the Exchange Fund. Subject to Sections 3.2(h) and (i), the Exchange Fund shall not be used for any purpose other than to pay such Merger Consideration.

(c) Exchange. Each holder of Class A Common Units that have been converted into the right to receive the Merger Consideration, upon delivery to the Paying Agent of a properly completed letter of transmittal, duly executed and completed in accordance with the instructions thereto, and surrender of Certificated Units (or affidavit of loss in lieu thereof pursuant to Section 3.2(g) with respect to Certificated Units) or Book-Entry Units and such other documents as may reasonably be required by the Paying Agent (including with respect to Book-Entry Units), will be entitled to receive in exchange therefor a check in an amount equal to the aggregate amount of cash that such holder has a right to receive pursuant to Section 3.1(a). The Merger Consideration shall be paid as promptly as practicable by mail after receipt by the Paying Agent of the Certificated Units (or affidavit of loss in lieu thereof pursuant to Section 3.2(g) with respect to Certificated Units) or any applicable documentation with respect to the surrender of Book-Entry Units, and letter of transmittal in accordance with the foregoing. No interest shall be paid or accrued on any Merger Consideration. Until so surrendered, each such Certificated Unit and Book-Entry Unit shall, after the Effective Time, represent for all purposes only the right to receive such Merger Consideration.

(d) Other Payees. If any payment of the Merger Consideration is to be made to a Person other than the Person in whose name the applicable surrendered Certificated Unit or Book-Entry Unit is registered, it shall be a condition of such payment that the Person requesting such payment shall pay any transfer or other similar Taxes required by reason of the making of such cash payment to a Person other than the registered holder of the surrendered Certificated Unit or Book-Entry Unit or shall establish to the satisfaction of the Paying Agent that such Tax has been paid or is not payable.

(e) No Further Transfers. From and after the Effective Time, there shall be no further registration on the books of the Partnership of transfers of Class A Common Units converted into the right to receive the Merger Consideration. From and after the Effective Time, the holders of Certificated Units or Book-Entry Units representing Class A Common Units converted into the right to receive the Merger Consideration which were outstanding immediately prior to the Effective Time shall cease to have any rights with respect to such Class A Common Units, except as otherwise provided in this Agreement or by applicable Law. If, after the Effective Time, Certificated Units or Book-Entry Units are presented to the Paying Agent or Parent, they shall be canceled and exchanged for the Merger Consideration provided for, and in accordance with the procedures set forth, in this Article III.

(f) Termination of Exchange Fund. Any portion of the Exchange Fund that remains unclaimed by the holders of Class A Common Units converted into the right to receive the Merger Consideration one year after the Effective Time shall be returned to Parent, upon demand, and any such holder who has not exchanged his, her or its Class A Common Units for the Merger Consideration in accordance with this Section 3.2 prior to that time shall thereafter look only to Parent for delivery of the Merger Consideration. Notwithstanding the foregoing, Parent, Merger Sub, the Partnership and the Partnership GP shall not be liable to any holder of Class A Common Units for any Merger Consideration duly delivered to a public official pursuant to applicable abandoned property Laws. Any Merger Consideration remaining unclaimed by holders of Class A Common Units immediately prior to such time as such amounts would otherwise escheat to, or become property of, any Governmental Authority shall, to the extent permitted by applicable Law, become the property of Parent free and clear of any claims or interest of any Person previously entitled thereto.

(g) Lost, Stolen or Destroyed Certificated Units. If any Certificated Unit shall have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the Person claiming such Certificated Unit to be lost,

 

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stolen or destroyed and, if required by Parent, the posting by such Person of a bond, in such reasonable amount as Parent may direct, as indemnity against any claim that may be made against it with respect to such Certificated Unit, the Paying Agent will issue in exchange for such lost, stolen or destroyed Certificated Unit the Merger Consideration to be paid in respect of the Class A Common Units represented by such Certificated Unit as contemplated by this Article III.

(h) Withholding Taxes. Each of Parent, Merger Sub, the Surviving Entity and the Paying Agent shall be entitled to deduct and withhold from the consideration otherwise payable to any Person pursuant to this Agreement such amounts, if any, as are required to be deducted and withheld with respect to the making of such payment under the Internal Revenue Code of 1986, as amended, and the rules and regulations promulgated thereunder (the “Code”), and the Treasury regulations promulgated thereunder, or under any provision of applicable state, local or foreign Tax Law. To the extent amounts are so withheld and paid over to the appropriate Tax authority, such withheld amounts shall be treated for the purposes of this Agreement as having been paid to the Person in respect of whom such withholding was made.

(i) Investment of the Exchange Fund. Parent may cause the Paying Agent to invest any cash included in the Exchange Fund as directed by Parent on a daily basis, in Parent’s sole discretion; provided, however, that any investment of such Exchange Fund shall be limited to cash and cash equivalents, direct short-term obligations of, or short-term obligations fully guaranteed as to principal and interest by, the U.S. government and money market funds comprised primarily of cash, cash equivalents and such obligations and that no such investment or loss thereon shall affect the amounts payable or the timing of the amounts payable to the holders of Certificated Units or Book-Entry Units representing Class A Common Units converted into the right to receive the Merger Consideration which were outstanding immediately prior to the Effective Time pursuant to this Article III. Any interest and other income resulting from such investments shall be paid promptly to Parent.

Section 3.3 Treatment of Partnership Incentive Awards; Termination of Partnership Equity Plan.

(a) Prior to the Effective Time, Parent and the Partnership GP will determine the terms and conditions of any adjustment(s), settlement(s) or substitution(s) to be made to or with respect to outstanding awards under the Partnership Long-Term Incentive Plan in connection with the Merger (each a “Partnership Incentive Plan Adjustment”), which Partnership Incentive Plan Adjustments, if any shall comply with Section 7(c) of the Partnership Long-Term Incentive Plan (or any other relevant provision of the Partnership Long-Term Incentive Plan or any award agreement thereunder) and shall become effective as of the Effective Time. Prior to the Effective Time, the Partnership and the Partnership GP shall take all actions as may be necessary or appropriate to implement the Partnership Incentive Plan Adjustments, if any, as determined by Parent and the Partnership GP.

(b) As soon as practicable following the Effective Time, the Partnership shall file a post-effective amendment to the Form S-8 registration statement filed by the Partnership on August 15, 2014, deregistering all Class A Common Units thereunder.

Section 3.4 Adjustments. Notwithstanding any provision of this Article III to the contrary, if between the date of this Agreement and the Effective Time the number of outstanding Class A Common Units shall have been changed into a different number of units or a different class or series by reason of the occurrence or record date of any unit distribution, subdivision, reclassification, recapitalization, split, split-up, combination, exchange of units or similar transaction, the Merger Consideration and any other similar dependent item, as the case may be, shall be appropriately adjusted to reflect fully the effect of such unit distribution, subdivision, reclassification, recapitalization, split, split-up, combination, exchange of units or similar transaction and to provide the holders of Class A Common Units the same economic effect as contemplated hereby prior to such event.

Section 3.5 No Dissenters’ Rights. No dissenters’ or appraisal rights shall be available with respect to the Merger or the other transactions contemplated hereby.

 

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ARTICLE IV.

REPRESENTATIONS AND WARRANTIES OF THE PARTNERSHIP AND THE

PARTNERSHIP GP

The Partnership and the Partnership GP represent and warrant, jointly and severally, to Parent as follows:

Section 4.1 Authority.

(a) Each of the Partnership and the Partnership GP has all necessary entity power and authority to execute and deliver this Agreement and to consummate the transactions contemplated hereby, subject to obtaining the Partnership Unitholder Approval in the case of the Partnership. The execution, delivery and performance by each of the Partnership and the Partnership GP of this Agreement, and the consummation by the Partnership and the Partnership GP of the transactions contemplated hereby, have been duly authorized by the GP Board and approved by each of the sole member of the Partnership GP, the GP Conflicts Committee and the GP Board and, except for obtaining the Partnership Unitholder Approval, no other entity action on the part of the Partnership or the Partnership GP is necessary to authorize the execution, delivery and performance by the Partnership and the Partnership GP of this Agreement and the consummation of the transactions contemplated hereby. This Agreement has been duly executed and delivered by the Partnership and the Partnership GP and, assuming due authorization, execution and delivery of this Agreement by the other parties hereto, constitutes a legal, valid and binding obligation of the Partnership and the Partnership GP, enforceable against each of the Partnership and the Partnership GP in accordance with its terms, subject, as to enforceability, to bankruptcy, insolvency and other Law of general applicability relating to or affecting creditors’ rights and to general equity principles.

(b) The execution, delivery and performance by the Partnership and the Partnership GP of this Agreement do not, and the consummation of the Merger (upon obtaining the Partnership Unitholder Approval) and compliance with the provisions of this Agreement will not, conflict with, or result in any violation of, or default (with or without notice or lapse of time, or both) under, or give rise to any right (including a right of termination, cancellation or acceleration of any obligation or any right of first refusal, participation or similar right) under, or cause the loss of any benefit under, or give rise to any right of notice, acceleration or termination under, or result in the creation of any Lien upon any of the properties or assets of the Partnership or the Partnership GP or any of their respective Subsidiaries under, any provision of (i) the Organizational Documents of the Partnership, the Partnership GP or any of the Partnership’s Subsidiaries, or (ii) subject to the filings and other matters referred to in Section 4.3, any Law applicable to the Partnership or the Partnership GP or any of their respective Subsidiaries or any of their respective properties or assets, other than, in the case of clause (ii) above, any such conflicts, violations, defaults, rights, losses or Liens that would not, individually or in the aggregate, reasonably be expected to prevent, materially delay or impair the ability of the Partnership or the Partnership GP to consummate the Merger or comply with their respective obligations under this Agreement or have a Material Adverse Effect on the Partnership (a “Partnership Material Adverse Effect”).

(c) The GP Conflicts Committee, at a meeting duly called and held, has (i) unanimously determined that each of the Merger, this Agreement and the transactions contemplated hereby is fair and reasonable to and in the best interests of the Partnership Group and the Partnership Unaffiliated Unitholders, (ii) approved this Agreement and the transactions contemplated hereby, including the Merger and the issuance of the New Class A Common Units, (iii) recommended that the GP Board approve this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger and the issuance of the New Class A Common Units, and (iv) recommended that the GP Board submit this Agreement to a vote of the Limited Partners and recommend approval of this Agreement by the Limited Partners. Such action by the GP Conflicts Committee described in clauses (i) and (ii) above constituted “Special Approval” (as defined in the Partnership Agreement) of this Agreement and the transactions contemplated hereby, including the Merger, under the Partnership Agreement.

 

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(d) The GP Board (acting based in part upon the recommendation of the GP Conflicts Committee), at a meeting duly called and held, has (i) determined that each of the Merger, this Agreement and the transactions contemplated hereby is fair and reasonable to and in the best interests of the Partnership Group and the Limited Partners, (ii) approved this Agreement, the execution, delivery and performance of this Agreement and the consummation of the transactions contemplated hereby, including the Merger and the issuance of the New Class A Common Units, (iii) resolved to submit this Agreement to a vote of the Limited Partners by written consent and (iv) recommended approval of this Agreement, including the Merger, by the Limited Partners.

Section 4.2 Capitalization.

(a) The authorized equity interests of the Partnership consist of Class A Common Units, Class B Common Units, Subordinated Units, General Partner Units and the Incentive Distribution Rights. At the close of business on January 26, 2017, the issued and outstanding limited partner interests and general partner interests of the Partnership consisted of (i) 22,610,056 Class A Common Units, (ii) zero Class B Common Units, (iii) 22,610,056 Subordinated Units, (iv) the Incentive Distribution Rights, and (v) 922,859.428571 General Partner Units. At the close of business on January 26, 2017, there were 1,018,741 performance stock units relating to Class A Common Units outstanding under the Partnership Long-Term Incentive Plan, which could be earned in cash at a “performance multiplier” of up to 200%. Except as set forth in Section 4.2(a) of the Partnership Disclosure Letter, as of the date of this Agreement there are not, and as of the Effective Time there will not be, any other Partnership Interests, voting securities or equity interests of the Partnership issued and outstanding or any subscriptions, options, restricted units, equity appreciation rights, profits interests, warrants, calls, convertible or exchangeable securities, rights, commitments or agreements of any character valued by reference to, or providing for the issuance of any Partnership Interests, voting securities or equity interests of the Partnership, including any representing the right to purchase or otherwise receive any of the foregoing. The outstanding Partnership Interests and the limited or general partner interests represented thereby were duly authorized and are validly issued in accordance with the Partnership Agreement and are fully paid (to the extent required under the Partnership Agreement) and nonassessable (except as such nonassessability may be affected by Sections 17-303, 17-607 and 17-804 of the DRULPA and except for the general partner interests), and, except as provided in the Partnership Agreement, are not subject to any preemptive or similar rights (and were not issued in violation of any preemptive or similar rights). The General Partner is the sole general partner of the Partnership and is the sole record owner of the General Partner Interest and all of the Incentive Distribution Rights and such General Partner Interest and Incentive Distribution Rights have been duly authorized and validly issued in accordance with applicable laws and the Partnership Agreement.

(b) None of the Partnership or any of its Subsidiaries has issued or is bound by any outstanding subscriptions, options, restricted units, equity appreciation rights, profits interests, warrants, calls, convertible or exchangeable securities, rights, commitments or agreements of any character providing for the issuance or disposition of any partnership interests, shares of capital stock, voting securities or equity interests of any Subsidiary of the Partnership. Except as set forth in the Partnership Agreement, there are no outstanding obligations of the Partnership or any of its Subsidiaries to repurchase, redeem or otherwise acquire any Partnership Interests or other partnership interests, shares of capital stock, voting securities or equity or equity-based interests (or any options, restricted units, equity appreciation rights, profits interests, warrants or other rights to acquire any Partnership Interests or other limited partnership interests, shares of capital stock, voting securities or equity interests) of the Partnership or any of its Subsidiaries.

(c) Other than ownership of its Subsidiaries, or as described in Section 4.2(c) of the Partnership Disclosure Letter, the Partnership does not own beneficially, directly or indirectly, any equity securities or similar interests of any Person, or any interest in a partnership or joint venture of any kind. Except as set forth in the Partnership SEC Documents, the Partnership owns such interests in its Subsidiaries free and clear of all Liens, except those existing or arising pursuant to the applicable governing documents of such entities.

Section 4.3 Governmental Approvals. No consent, approval, order or authorization of, or registration, declaration or filing with, or notice to, any Governmental Authority is required to be obtained or made by or with

 

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respect to the Partnership or any of its Subsidiaries in connection with the execution, delivery and performance of this Agreement by the Partnership or the Partnership GP or the consummation by the Partnership or the Partnership GP of the transactions contemplated by this Agreement, including the Merger, except for (a) any filings required or advisable under any applicable antitrust or competition Law, (b) the filing with the SEC of such reports under Exchange Act as may be required in connection with this Agreement and the transactions contemplated hereby, (c) the filing of the Certificate of Merger with the Secretary of State of the State of Delaware, (d) the filing of a Schedule 13E-3, (e) any filings required under the rules and regulations of the NYSE, (f) any consents, approvals, orders, authorizations, registrations, declarations, filings and notices required for the Partnership or the Partnership GP to perform their respective obligations under Section 6.4 and (g) such other consents, approvals, orders, authorizations, registrations, declarations, filings and notices, the failure of which to be obtained or made would not, individually or in the aggregate, reasonably be expected to prevent, materially delay or impair the ability of Partnership or the Partnership GP to consummate the Merger or comply with their respective obligations under this Agreement or have a Partnership Material Adverse Effect.

Section 4.4 Legal Proceedings. Except as has not prevented, materially delayed or impaired, and would not reasonably be expected to prevent, materially delay or impair, the ability of the Partnership or Partnership GP to consummate the Merger or comply with their respective obligations under this Agreement, as of the date hereof, (a) there is no Proceeding pending or, to the Knowledge of the Partnership or the Partnership GP, threatened against, or, to the Knowledge of the Partnership or the Partnership GP, any pending or threatened material governmental or regulatory investigation of, Partnership or any of its Subsidiaries and (b) there is no injunction, order, judgment, ruling, decree or writ of any Governmental Authority outstanding or, to the Knowledge of the Partnership or the Partnership GP, threatened to be imposed, against Partnership or any of its Subsidiaries.

Section 4.5 Opinion of Financial Advisor. The GP Conflicts Committee has received the opinion of Evercore Group L.L.C. (the “Partnership Financial Advisor”), dated as of January 26, 2017, to the effect that, as of such date, and based upon and subject to the assumptions, qualifications, limitations and other matters set forth therein, the Merger Consideration to be received by the Partnership Unaffiliated Unitholders pursuant to this Agreement is fair, from a financial point of view, to the Partnership Unaffiliated Unitholders (the “Partnership Fairness Opinion”). The Partnership shall forward to Parent, solely for informational purposes, a copy of such written opinion promptly following the execution of this Agreement.

Section 4.6 Brokers and Other Advisors. Except for the Partnership Financial Advisor, the fees and expenses of which will be paid by the Partnership, no broker, investment banker or financial advisor is entitled to any broker’s, finder’s or financial advisor’s fee or commission, or the reimbursement of expenses, in connection with the Merger or the transactions contemplated hereby based on arrangements made by or on behalf of the GP Conflicts Committee. The Partnership has heretofore made available to Parent a correct and complete copy of the Partnership’s engagement letter with the Partnership Financial Advisor, which letter describes all fees payable to the Partnership Financial Advisor in connection with the transactions contemplated hereby and all agreements under which any such fees or any expenses are payable and all indemnification and other agreements with the Partnership Financial Advisor entered into in connection with the transactions contemplated hereby.

Section 4.7 Disclosure Letter. On or prior to the date hereof, the Partnership and the Partnership GP have delivered to Parent a letter (the “Partnership Disclosure Letter”) setting forth, among other things, items the disclosure of which is necessary or appropriate in relation to any or all of their respective representations and warranties; provided, however, that (a) no such item is required to be set forth in the Partnership Disclosure Letter as an exception to a representation or warranty if its absence is not reasonably likely to result in the related representation or warranty being deemed untrue or incorrect in any material respect, and (b) the mere inclusion of an item in the Partnership Disclosure Letter shall not be deemed an admission by a party that such item represents a material exception or fact, event or circumstance or that such item is reasonably likely to result in a Partnership Material Adverse Effect.

Section 4.8 No Other Representations or Warranties. Except for the representations and warranties set forth in this Article IV, neither the Partnership nor any other Person makes or has made any other express or implied

 

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representation or warranty with respect to the Partnership or with respect to any other information provided to Parent or Merger Sub in connection with the Merger or the other transactions contemplated hereby. Without limiting the generality of the foregoing, neither the Partnership nor any other Person will have or be subject to any liability or other obligation to Parent or Merger Sub or any other Person resulting from the distribution to Parent or Merger Sub (including their respective Representatives), or Parent’s or Merger Sub’s (or such Representatives’) use of, any such information, including any information, documents, projections, forecasts or other materials made available to Parent or Merger Sub in expectation of the Merger, unless any such information is the subject of an express representation or warranty set forth in this Article IV. The Partnership and Partnership GP acknowledge and agree that, except for the representations and warranties contained in Article V, the Partnership and Partnership GP have not relied on and none of Parent, Merger Sub or any of their respective Affiliates or Representatives has made any representation or warranty, either express or implied, whether written or oral, concerning Parent, Merger Sub or any of their respective Affiliates or any of their respective businesses, operations, assets, liabilities, results of operations, condition (financial or otherwise) or prospects, the transactions contemplated by this Agreement or otherwise with respect to information provided by or on behalf of Parent, Merger Sub or any of their respective Affiliates or Representatives.

ARTICLE V.

REPRESENTATIONS AND WARRANTIES OF PARENT AND MERGER SUB

As an inducement for the Partnership to enter into this Agreement, Parent and Merger Sub hereby represent and warrant, jointly and severally, to the Partnership and the Partnership GP as follows:

Section 5.1 Organization, Standing and Corporate Power. Each of Parent and Merger Sub is a legal entity duly organized, validly existing and in good standing under the Law of its respective jurisdiction of organization and has all requisite corporate or limited liability company, as applicable, power and authority to carry on its business as presently conducted and is duly qualified or licensed to do business and is in good standing (where such concept is recognized under applicable Law) in each jurisdiction where the nature of its business or the ownership, leasing or operation of its properties makes such qualification or licensing necessary, other than where the failure to be so qualified, licensed or in good standing would not, individually or in the aggregate, reasonably be expected to prevent, materially delay or impair the ability of Parent or Merger Sub to consummate the Merger or comply with their respective obligations under this Agreement. Parent has made available to the Partnership prior to the execution of this Agreement a true and complete copy of the Organizational Documents of Parent (the “Parent Organizational Documents”) and the Organizational Documents of Merger Sub, in each case, as in effect as of the date of this Agreement.

Section 5.2 Operations and Ownership of Merger Sub. All of the issued and outstanding limited liability company interests of Merger Sub are beneficially owned by Parent. All of the issued and outstanding shares of common stock of Parent are indirectly owned by Enbridge. Merger Sub was formed solely for the purpose of engaging in the transactions contemplated hereby. Except for obligations and liabilities incurred in connection with its formation and the transactions contemplated hereby, Merger Sub has not and will not have incurred, directly or indirectly, any obligations or engaged in any business activities of any type or kind whatsoever or entered into any agreements or arrangements with any Person.

Section 5.3 Ownership of Partnership Units. As of the date of this Agreement, EEP is the record owner of 1,335,056 Class A Common Units and the sole record owner of 22,610,056 Subordinated Units, which represent (i) all outstanding Subordinated Units and (ii) all Units held of record or beneficially by Parent or any of its Subsidiaries.

Section 5.4 Authority; Noncontravention.

 

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(a) Each of Parent and Merger Sub has all requisite corporate or limited liability company, as applicable, power and authority to execute and deliver, and perform its obligations under, this Agreement and to consummate the transactions contemplated hereby. The execution, delivery and performance of this Agreement by each of Parent and Merger Sub and the consummation by Parent and Merger Sub of the transactions contemplated hereby have been duly authorized by all necessary corporate or limited liability company action on the part of each of Parent and Merger Sub. This Agreement has been duly executed and delivered by each of Parent and Merger Sub and, assuming the due authorization, execution and delivery by the Partnership and the Partnership GP, constitutes a legal, valid and binding obligation of each of Parent and Merger Sub, enforceable against each of Parent and Merger Sub in accordance with its terms, subject, as to enforceability, to bankruptcy, insolvency and other Laws of general applicability relating to or affecting creditors’ rights and to general equity principles. The Parent Board has duly and validly adopted resolutions approving and declaring advisable this Agreement and the transactions contemplated hereby, including the Merger, and authorizing Parent, as sole member of Merger Sub, to cause Merger Sub to enter into this Agreement and consummate the Merger and the other transactions contemplated hereby on the terms and subject to the conditions set forth in this Agreement, which resolutions of Parent have not been rescinded, modified or withdrawn in any way.

(b) The execution, delivery and performance by Parent and Merger Sub of this Agreement do not, and the consummation of the Merger and compliance with the provisions of this Agreement will not, conflict with, or result in any violation of, or default (with or without notice or lapse of time, or both) under, or give rise to any right (including a right of termination, cancellation or acceleration of any obligation or any right of first refusal, participation or similar right) under, or cause the loss of any benefit under, or give rise to any right of notice, acceleration or termination under, or result in the creation of any Lien upon any of the properties or assets of Parent or Merger Sub or any of their respective Subsidiaries under, any provision of (i) the Parent Organizational Documents or the Organizational Documents of any of Parent’s Subsidiaries, including Merger Sub, or (ii) subject to the filings and other matters referred to in Section 5.5, (A) any Contract to which Parent or Merger Sub or any of their respective Subsidiaries is a party or by which any of their respective properties or assets are bound or (B) any Law applicable to Parent or Merger Sub or any of their respective Subsidiaries or any of their respective properties or assets, other than, in the case of clause (ii) above, any such conflicts, violations, defaults, rights, losses or Liens that would not, individually or in the aggregate, reasonably be expected to prevent, materially delay or impair the ability of Parent or Merger Sub to consummate the Merger or comply with their respective obligations under this Agreement.

(c) Simultaneously with the execution of this Agreement, EEP will have executed and delivered the EEP Support Agreement.

Section 5.5 Governmental Approvals. No consent, approval, order or authorization of, or registration, declaration or filing with, or notice to, any Governmental Authority is required to be obtained or made by or with respect to Parent or Merger Sub or any of their respective Subsidiaries in connection with the execution, delivery and performance of this Agreement by Parent and Merger Sub or the consummation by Parent and Merger Sub of the Merger, except for (a) any filings required or advisable under any applicable Antitrust Laws, (b) the filing with the SEC of such reports under the Exchange Act as may be required in connection with this Agreement and the transactions contemplated hereby, (c) the filing of the Certificate of Merger with the Secretary of State of the State of Delaware, (d) the filing of a Schedule 13E-3, (e) any filings required under the rules and regulations of the NYSE, (f) any consents, approvals, orders, authorizations, registrations, declarations, filings and notices required for Parent or Merger Sub to perform their respective obligations under Section 6.4 and (g) such other consents, approvals, orders, authorizations, registrations, declarations, filings and notices, the failure of which to be obtained or made would not, individually or in the aggregate, reasonably be expected to prevent, materially delay or impair the ability of Parent or Merger Sub to consummate the Merger or comply with their respective obligations under this Agreement.

Section 5.6 Legal Proceedings. Except as has not prevented, materially delayed or impaired, and would not reasonably be expected to prevent, materially delay or impair, the ability of Parent or Merger Sub to consummate

 

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the Merger or comply with their respective obligations under this Agreement, as of the date hereof, (a) there is no Proceeding pending or, to the Knowledge of Parent, threatened against, or, to the Knowledge of Parent, any pending or threatened material governmental or regulatory investigation of, Parent or any of its Subsidiaries and (b) there is no injunction, order, judgment, ruling, decree or writ of any Governmental Authority outstanding or, to the Knowledge of Parent, threatened to be imposed, against Parent or any of its Subsidiaries.

Section 5.7 Access to Information. Each of Parent and Merger Sub acknowledges that it has conducted its own independent investigation and analysis of the business, operations, assets, liabilities, results of operations, condition and prospects of the Partnership and its Subsidiaries and that it and its Representatives have received access to such books, records and facilities, equipment, Contracts and other assets of the Partnership and its Subsidiaries that it and its Representatives have requested for such purposes and that it and its Representatives have had the opportunity to meet with management of the Partnership to discuss the foregoing, and that it and its Representatives have not relied on any representation, warranty or other statement by any Person on behalf of the Partnership or any of its Subsidiaries, other than the representations and warranties expressly set forth in Article IV.

Section 5.8 Information Supplied. None of the information supplied (or to be supplied) in writing by or on behalf of Parent specifically for inclusion or incorporation by reference in (a) the Partnership Information Statement, on the date it is first mailed to the Limited Partners, will contain any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they are made, not misleading or (b) the Schedule 13E-3 will, at the time the Schedule 13E-3, or any amendment or supplement thereto, is filed with the SEC, contain any untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in light of the circumstances under which they are made, not misleading. Notwithstanding the foregoing, Parent makes no representation or warranty with respect to information supplied by or on behalf of the Partnership for inclusion or incorporation by reference in any of the foregoing documents.

Section 5.9 Brokers and Other Advisors. Except for Citigroup Global Markets, Inc., the fees and expenses of which will be paid by Parent or an Affiliate thereof, no broker, investment banker or financial advisor is entitled to any broker’s, finder’s or financial advisor’s fee or commission, or the reimbursement of expenses, in connection with the transactions contemplated hereby based on arrangements made by or on behalf of Parent, Merger Sub or any of their respective Affiliates.

Section 5.10 Available Funds. At the Effective Time, Parent will have available to it sources of immediately available funds sufficient to consummate the Merger and to pay all amounts required to be paid in connection with the transactions contemplated by this Agreement, including the Merger Consideration.

Section 5.11 Disclosure Letter. On or prior to the date hereof, Parent and Merger Sub have delivered to the Partnership and the Partnership GP the Parent Disclosure Letter setting forth, among other things, items the disclosure of which is necessary or appropriate in relation to any or all of their respective representations and warranties; provided, however, that (a) no such item is required to be set forth in the Parent Disclosure Letter as an exception to a representation or warranty if its absence is not reasonably likely to result in the related representation or warranty being deemed untrue or incorrect in any material respect, and (b) the mere inclusion of an item in the Parent Disclosure Letter shall not be deemed an admission by a party that such item represents a material exception or fact, event or circumstance or that such item is reasonably likely to result in a Material Adverse Effect to Parent.

Section 5.12 No Other Representations or Warranties. Except for the representations and warranties contained in this Article V, the Partnership acknowledges that none of Parent or Merger Sub or any other Person on behalf of Parent or Merger Sub makes or has made any other express or implied representation or warranty with respect to, Parent or Merger Sub or with respect to any other information provided to the Partnership, the Partnership GP, the GP Board, the GP Conflicts Committee or their Representatives. Without limiting the

 

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generality of the foregoing, except to the extent required otherwise by applicable Law, neither Parent nor any other Person will have or be subject to any liability or other obligation to the Partnership or the Partnership GP or any other Person resulting from the distribution to the Partnership, the Partnership GP, the GP Board or the GP Conflicts Committee (including their respective Representatives), or the Partnership’s or the Partnership GP’s (or such Representatives’) use of, any such information, including any information, documents, projections, forecasts or other materials made available to the Partnership, the Partnership GP, the GP Board, the GP Conflicts Committee or their Representatives in expectation of the Merger, unless any such information is the subject of an express representation or warranty set forth in this Article V. Parent and Merger Sub acknowledge and agree that, except for the representations and warranties contained in Article IV, Parent and Merger Sub have not relied on and none of the Partnership, Partnership GP or any of their respective Affiliates or Representatives has made any representation or warranty, either express or implied, whether written or oral, concerning the Partnership, the Partnership GP or any of their respective Affiliates or any of their respective businesses, operations, assets, liabilities, results of operations, condition (financial or otherwise) or prospects, the transactions contemplated by this Agreement or otherwise with respect to information provided by or on behalf of the Partnership, the Partnership GP or any of their respective Affiliates or Representatives.

ARTICLE VI.

ADDITIONAL COVENANTS AND AGREEMENTS

Section 6.1 Preparation of the Partnership Information Statement and Schedule 13E-3.

(a) As promptly as practicable following the date of this Agreement, the Partnership and Parent and Merger Sub shall jointly prepare and file with the SEC the Schedule 13E-3 and any amendments thereto as required by Rule 13e-3 under the Exchange Act, and the Partnership and Parent shall prepare and the Partnership shall file with the SEC the Partnership Information Statement. Each of the Partnership and Parent shall use its commercially reasonable efforts to cause the Partnership Information Statement to be mailed to the Limited Partners as promptly as practicable after the date of this Agreement. Each of Parent, Merger Sub, the Partnership and the Partnership GP shall cooperate and consult with each other in connection with the preparation and filing of the Partnership Information Statement and the Schedule 13E-3, as applicable, including promptly furnishing to each other in writing upon request any and all information relating to a party or its Affiliates as may be required to be set forth in the Partnership Information Statement or the Schedule 13E-3, as applicable, under applicable Law. If at any time prior to the Effective Time any information relating to the Partnership or Parent, or any of their respective Affiliates, directors or officers, is discovered by the Partnership or Parent that should be set forth in an amendment or supplement to, the Partnership Information Statement or the Schedule 13E-3, so that any such document would not include any misstatement of a material fact or omit to state any material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, the party that discovers such information shall promptly notify the other parties hereto and an appropriate amendment or supplement describing such information shall be promptly filed with the SEC and, to the extent required by applicable Law, disseminated to the Limited Partners. The parties shall notify each other promptly of the receipt of any comments, written or oral, from the SEC or the staff of the SEC and of any request by the SEC or the staff of the SEC for amendments or supplements to the Partnership Information Statement, the Schedule 13E-3 or for additional information and each party shall supply the other with copies of all correspondence between it or any of its Representatives, on the one hand, and the SEC or the staff of the SEC, on the other hand, with respect to the Partnership Information Statement, the Schedule 13E-3 or the transactions contemplated hereby. The Partnership, with Parent’s and Merger Sub’s cooperation, shall use commercially reasonable efforts to respond as promptly as reasonably practicable to and use commercially reasonable efforts to resolve all comments received from the SEC or the staff of the SEC concerning the Partnership Information Statement as promptly as reasonably practicable and shall respond (with the cooperation of, and after consultation with, Parent and Merger Sub as provided by this Section 6.1) as promptly as reasonably practicable to, and use commercially reasonable efforts to resolve, all comments received from the SEC or the staff of the SEC concerning the

 

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Schedule 13E-3 as promptly as reasonably practicable. No filing of, or amendment or supplement to, including by incorporation by reference, or correspondence with the SEC with respect to the Partnership Information Statement or the Schedule 13E-3 will be made by the Partnership, Parent or Merger Sub, as applicable, without providing the Partnership, Parent or Merger Sub, as applicable, a reasonable opportunity to review and comment thereon, which comments the Partnership, Parent or Merger Sub, as applicable, shall consider and implement in good faith.

(b) Subject to Section 6.3, the Partnership shall, through the GP Board, recommend to the Limited Partners approval of this Agreement and the Merger (collectively, the “Partnership Board Recommendation”). The Partnership Information Statement shall include a copy of the Partnership Fairness Opinion and, subject to Section 6.3, the Partnership Board Recommendation. Without limiting the generality of the foregoing, but subject to Section 6.3, the Partnership’s obligations pursuant to the first sentence of this Section 6.1(b) shall not be affected by the withdrawal or modification of the Partnership Board Recommendation or the GP Conflicts Committee’s or the GP Board’s approval of this Agreement or the transactions contemplated hereby.

Section 6.2 Conduct of Business. Except (i) as provided in this Agreement, (ii) as required by applicable Law, (iii) as provided in any Material Contract in effect as of the date of this Agreement, (iv) as provided in the Partnership Agreement or (v) as consented to in writing by Parent (which consent shall not be unreasonably withheld, delayed or conditioned (it being understood that this parenthetical will have no effect on any rights of Parent or its Affiliates have to consent to any of the actions in this Section 6.2 in any other Contract or agreement)), during the period from the date of this Agreement until the Effective Time, each of the Partnership GP and the Partnership shall not, and shall cause each of their respective Subsidiaries not to, and Parent shall not cause Partnership or Partnership GP to:

(a) (i) (A) conduct its business and the business of its Subsidiaries other than in the ordinary course, or (B) fail to use commercially reasonable efforts to preserve intact its business organization, goodwill and assets and maintain its rights, franchises and existing relations with customers, suppliers, employees and business associates, except in either case of clause (A) or (B) that could not reasonably be expected to have a Partnership Material Adverse Effect or (ii) take any action that could reasonably be expected to have a Partnership Material Adverse Effect, or materially delay any approvals required for, or the consummation of, the transactions contemplated hereby;

(b) other than the New Class A Common Units and annual compensatory equity awards granted to non-employee directors of the GP Board in the ordinary course, (i) issue, sell or otherwise permit to become outstanding, or authorize the creation of, any additional equity securities (other than pursuant to the existing terms of Rights outstanding as of the date of this Agreement, if any) or any additional Rights, (ii) enter into any agreement with respect to the foregoing, in each case which would materially adversely affect its ability to consummate the transactions contemplated hereby, or (iii) except as expressly contemplated by this Agreement, issue, grant or amend any award under the Partnership Long-Term Incentive Plan;

(c) (i) split, combine or reclassify any of its equity interests or authorize or propose the issuance of any other securities in respect of, in lieu of or in substitution for its equity interests or (ii) repurchase, redeem or otherwise acquire, or permit any of its Subsidiaries to purchase, redeem or otherwise acquire, any partnership or other equity interests or Rights, except as required by the terms of its securities outstanding on the date hereof by the Partnership Long-Term Incentive Plan;

(d) (i) sell, lease or dispose of any portion of its assets, business or properties other than in the ordinary course of business (including distributions permitted under Section 6.2(e)), (ii) acquire, by merger or otherwise, or lease any assets or all or any portion of the business or property of any other entity other than in the ordinary course of business consistent with past practice or (iii) convert from a limited partnership or limited liability company, as the case may be, to any other business entity;

 

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(e) make or declare distributions to the holders of any Units or other equity interests in the Partnership, in each case other than in the ordinary course of business pursuant to Section 6.2(a) and Section 6.17;

(f) amend the Partnership Agreement, as in effect on the date of this Agreement;

(g) enter into any Material Contract, except as would not have a Partnership Material Adverse Effect and as would not be materially adverse to Parent, Merger Sub and their respective Subsidiaries, taken as a whole;

(h) modify, amend, terminate or assign, or waive or assign any rights under, any Material Contract in a manner which is materially adverse to Parent, Merger Sub and their respective Subsidiaries, taken as a whole, or which would have a Partnership Material Adverse Effect;

(i) waive, release, assign, settle or compromise any Proceeding, including any state or federal regulatory Proceeding, seeking damages or injunction or other equitable relief, that (i) is material to the Partnership and its Subsidiaries, taken as a whole, or (ii) is a claim, action or Proceeding relating to the transactions contemplated hereby;

(j) implement or adopt any material change in its accounting principles, practices or methods, other than as may be required by GAAP or other applicable regulatory authorities;

(k) (i) change its fiscal year or any method of Tax accounting, (ii) make, change or revoke any material Tax election, (iii) settle or compromise any material liability for Taxes, (iv) file any material amended Tax Return or (v) take any action or fail to take any action that would reasonably be expected to cause the Partnership or any of its Subsidiaries to be treated, for U.S. federal income Tax purposes, as a corporation;

(l) other than in the ordinary course of business consistent with past practice, (i) incur, assume, guarantee or otherwise become liable for any indebtedness (directly, contingently or otherwise), other than borrowings under existing revolving credit facilities or intercompany money pool arrangements, or (ii) create any Lien on its property or the property of its Subsidiaries to secure indebtedness;

(m) authorize, recommend, propose or announce an intention to adopt a plan of complete or partial dissolution or liquidation;

(n) knowingly take any action that is intended or is reasonably likely to result in (i) any of its representations and warranties set forth in this Agreement being or becoming untrue in any material respect at the Closing Date, (ii) any of the conditions set forth in Article VII not being satisfied, (iii) any material delay or prevention of the consummation of the Merger or (iv) a material violation of any provision of this Agreement; or

(o) agree or commit to do anything prohibited by clauses (a) through (n) of this Section 6.2.

Section 6.3 Partnership Adverse Recommendation Change.

(a) The Partnership shall, and Partnership GP shall cause its, and the Partnership’s and its Subsidiaries’ respective directors, officers, employees, investment bankers, financial advisors, attorneys, accountants, agents and other representatives (collectively, “Representatives”) to, immediately cease and cause to be terminated any discussions or negotiations with any Person conducted heretofore with respect to an Acquisition Proposal, require the return or destruction of all confidential information previously provided to such parties by or on behalf of the Partnership or its Subsidiaries and immediately prohibit any access by any Person (other than Parent and its Representatives) to any physical or electronic data room relating to a possible Acquisition Proposal. Neither the Partnership nor the Partnership GP shall, and the Partnership shall cause its Subsidiaries and their respective Representatives not to, directly or indirectly, (i) initiate, solicit, knowingly encourage or knowingly facilitate (including by way of furnishing confidential information) or take any other action intended to lead to any

 

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inquiries or the making or submission of any proposal that constitutes, or may reasonably be expected to lead to, an Acquisition Proposal, (ii) participate in any discussions or negotiations regarding, or furnish to any Person any non-public information with respect to, any Acquisition Proposal, (iii) enter into any confidentiality agreement, merger agreement, letter of intent, agreement in principle, unit purchase agreement, asset purchase agreement or unit exchange agreement, option agreement or similar agreement relating to an Acquisition Proposal, or (iv) withdraw, modify or qualify, or propose publicly to withdraw, modify or qualify, in a manner adverse to Parent, the Partnership Board Recommendation or publicly recommend the approval or adoption of, or publicly approve or adopt, or propose to publicly recommend, approve or adopt, any Acquisition Proposal, or fail to recommend against acceptance of any tender offer or exchange offer for Class A Common Units within ten (10) Business Days after commencement of such offer, or resolve or agree to take any of the foregoing actions. Without limiting the foregoing, it is understood and agreed that (a) any violation of the foregoing restrictions by the Partnership’s Subsidiaries or Representatives acting by or on behalf of the Partnership will be deemed to be a breach of this Section 6.3 by the Partnership and (b) no act or failure to act by Parent or any of its Affiliates or Representatives shall be a violation or breach of this Section 6.3 by the Partnership or the Partnership GP. Notwithstanding the foregoing, but subject to the limitations in Sections 6.3(c) and (d), at any time prior to obtaining the Partnership Unitholder Approval, nothing contained in this Agreement shall prohibit the Partnership, the Partnership GP or any of their Representatives from furnishing or making available any information or data pertaining to the Partnership, or entering into or participating in discussions or negotiations with, any Person that makes an unsolicited written Acquisition Proposal that did not result from a material, knowing and intentional breach of this Section 6.3 (a “Receiving Party”), if, and only to the extent that (i) the GP Board after consultation with its outside legal counsel and financial advisor and the GP Conflicts Committee, determines in its good faith judgment (A) that such Acquisition Proposal constitutes or is likely to result in a Superior Proposal, and (B) that failure to take such action would be materially adverse to the interests of the Partnership Unaffiliated Unitholders or otherwise inconsistent with the GP Board’s duties under the Partnership Agreement or applicable Law and (ii) prior to furnishing or making available any such non-public information to such Receiving Party, the Partnership receives from such Receiving Party an executed Confidentiality Agreement.

(b) Except as permitted by this Section 6.3, the Partnership and the Partnership GP shall not, and shall cause their respective Subsidiaries and their Representatives not to, directly or indirectly (i) take any action set forth in clause (iv) of Section 6.3(a) of this Agreement or (ii) fail to include the Partnership Board Recommendation in the Partnership Information Statement (the taking of any action described in clauses (i) or (ii) being referred to as a “Partnership Adverse Recommendation Change”). Without limiting the foregoing, it is understood that any violation of the foregoing restrictions by the Partnership’s or the Partnership GP’s Subsidiaries, or the Partnership’s or the Partnership GP’s Representatives shall be deemed to be a breach of this Section 6.3 by the Partnership and the Partnership GP.

(c) Notwithstanding anything to the contrary in this Agreement, at any time prior to obtaining the Partnership Unitholder Approval, and subject to compliance in all material respects with this Section 6.3(c), the GP Board, after consulting with the GP Conflicts Committee, may make a Partnership Adverse Recommendation Change if the GP Board determines in good faith (after consultation with its financial advisor and outside legal counsel and the GP Conflicts Committee) (i) that an Acquisition Proposal constitutes a Superior Proposal and (ii) that the failure to take such action would be materially adverse to the interests of the Partnership Unaffiliated Unitholders or otherwise inconsistent with the GP Board’s duties under the Partnership Agreement or applicable Law, provided, however, that the GP Board may not effect a Partnership Adverse Recommendation Change pursuant to the foregoing unless:

(i) the GP Board has provided prior written notice to Parent specifying in reasonable detail the reasons for such action at least five days in advance of its intention to take such action with respect to a Partnership Adverse Recommendation Change unless at the time such notice is otherwise required to be given there are fewer than five days prior to the expected date of the Partnership Unitholder Approval, in which case such notice shall be provided as far in advance as practicable (“Notice of Proposed Adverse Recommendation

 

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Change”). The Notice of Proposed Adverse Recommendation Change shall include, if applicable, the material terms and conditions of any Superior Proposal that is the basis of the proposed action and the identity of the Person making the proposal (it being understood and agreed that any material amendment to the terms of any such Superior Proposal shall require a new Notice of Proposed Adverse Recommendation Change and an additional five day period)(the period inclusive of all such days, the “Partnership Notice Period”);

(ii) if applicable, Parent has been provided all materials and information delivered or made available to the Person or group of persons making any Superior Proposal in connection with such Superior Proposal (to the extent not previously provided); and

(iii) during the Partnership Notice Period, the GP Board has negotiated, and has used its reasonable best efforts to cause its financial advisors and outside legal counsel to negotiate, with Parent in good faith (to the extent Parent desires to negotiate in its sole discretion) to make such adjustments in the terms and conditions of this Agreement so that the failure to effect such Partnership Adverse Recommendation Change would not be materially adverse to the interests of the Partnership Unaffiliated Unitholders or otherwise inconsistent with the GP Board’s duties under the Partnership Agreement or applicable Law, provided, however, that the GP Board or GP Conflicts Committee, as applicable, shall take into account all changes to the terms of this Agreement proposed by Parent in determining whether to make, or in the case of the GP Conflicts Committee, recommend, a Partnership Adverse Recommendation Change.

(d) In addition to the other obligations of the Partnership set forth in this Section 6.3, the Partnership shall promptly advise Parent and the GP Board, orally and in writing, and in no event later than 24 hours after receipt, if any proposal, offer, inquiry or other contact is received by, any information is requested from, or any discussions or negotiations are sought to be initiated or continued with, the Partnership in respect of any Acquisition Proposal, and shall, in any such notice to Parent and the GP Board, indicate the identity of the Person making such proposal, offer, inquiry or other contact and the terms and conditions of any proposals or offers or the nature of any inquiries or contacts (and shall include with such notice copies of any written materials received from or on behalf of such Person relating to such proposal, offer, inquiry or request), and thereafter shall promptly keep Parent and the GP Board reasonably informed of all material developments affecting the status and terms of any such proposals, offers, inquiries or requests (and the Partnership shall promptly provide Parent and the GP Board with copies of any additional written materials received by the Partnership or that the Partnership has delivered to any third party making an Acquisition Proposal that relate to such proposals, offers, inquiries or requests) and of the status of any such discussions or negotiations.

Section 6.4 Consummation of the Merger.

(a) Subject to the terms and conditions of this Agreement, Parent, on the one hand, and each of the Partnership and the Partnership GP, on the other hand, shall cooperate with the other and use and shall cause their respective Subsidiaries to use its commercially reasonable efforts to (i) take, or cause to be taken, all actions, and do, or cause to be done, all things, necessary, proper or advisable to cause the conditions to the Closing to be satisfied as promptly as practicable (and in any event no later than the Outside Date) and to consummate and make effective, in the most expeditious manner practicable, the transactions contemplated hereby, including preparing and filing as promptly as practicable all documentation to effect all necessary filings, notifications, notices, petitions, statements, registrations, submissions of information, applications and other documents (including any required or recommended filings under applicable Antitrust Laws), (ii) obtain promptly (and in any event no later than the Outside Date) all approvals, consents, clearances, expirations or terminations of waiting periods, registrations, Permits, authorizations and other confirmations from any Governmental Authority or third party necessary, proper or advisable to consummate the transactions contemplated hereby and (iii) defend any Proceedings challenging this Agreement or the consummation of the transactions contemplated hereby.

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(ii) directly or indirectly (A) sell, transfer, assign, tender in any tender or exchange offer, pledge, encumber, hypothecate or similarly dispose of (by merger, by distribution, by operation of Law or otherwise), either voluntarily or involuntarily, or enter into any Contract, option or other arrangement or understanding with respect to the sale, transfer, assignment, pledge, encumbrance, hypothecation or other disposition of (by merger, by distribution, by operation of Law or otherwise), any Units owned by EEP as of the date hereof, (B) deposit any Units into a voting trust or enter into a voting agreement or arrangement or grant any proxy, consent or power of attorney with respect thereto other than, and that is inconsistent with, this Section 6.4(b), or (C) agree (regardless of whether in writing) to take any of the actions referred to in the foregoing clauses (A) or (B). In addition, Parent shall not at any time on or before the Effective Time or the earlier termination of this Agreement, directly or indirectly, by merger or otherwise, sell, transfer, assign, pledge, encumber, hypothecate or similarly dispose of, either voluntarily or involuntarily, or enter into any Contract, option or other arrangement or understanding with respect to the sale, transfer, assignment, pledge, encumbrance, hypothecation or other disposition of, any equity or other ownership interest in EEP.

(c) Until the Effective Time or the earlier termination of this Agreement, Parent will not, and will not recommend or direct any of its Subsidiaries to, acquire record or beneficial ownership of any additional Units.

Section 6.5 Public Announcements. The initial press release or releases with respect to the execution of this Agreement shall be reasonably agreed upon by Parent and the Partnership. Thereafter, neither the Partnership nor Parent shall issue or cause the publication of any press release or other public announcement (to the extent not previously issued or made in accordance with this Agreement) with respect to this Agreement or the transactions contemplated hereby without the prior consent of the other party (which consent shall not be unreasonably withheld, conditioned or delayed), except as may be required by applicable Law or by any applicable listing agreement with the NYSE or other national securities exchange as determined in the good faith judgment of the party proposing to make such release (in which case such party shall not issue or cause the publication of such press release or other public announcement without prior consultation with the other party); provided, however, that the Partnership shall not be required by this Section 6.5 to consult with any other party with respect to a public announcement in connection with a Partnership Adverse Recommendation Change but nothing in this proviso shall limit the obligations of the Partnership, the Partnership GP, the GP Board or the GP Conflicts Committee under Section 6.3; provided, further, that each party and their respective controlled Affiliates may make statements that are consistent with statements made in previous press releases, public disclosures or public statements made by Parent, the Partnership or the Partnership GP in compliance with this Section 6.5.

Section 6.6 Access to Information. Upon reasonable advance notice and subject to applicable Laws relating to the exchange of information, each party shall, and shall cause each of its Subsidiaries to afford to the other party and its Representatives reasonable access during normal business hours (and, with respect to books and records, the right to copy) to all of its and its Subsidiaries’ properties, commitments, books, Contracts, records and correspondence (in each case, whether in physical or electronic form), officers, employees, accountants, counsel, financial advisors and other Representatives.

Section 6.7 Indemnification and Insurance.

(a) From and after the Effective Time, solely to the extent that the Partnership or the Partnership GP or any applicable Subsidiary thereof would be permitted to indemnify an Indemnified Person immediately prior to the Effective Time, the Surviving Entity and the Partnership GP jointly and severally agree to (i) indemnify, defend and hold harmless against any cost or expenses (including attorneys’ fees), judgments, settlements, fines and other sanctions, losses, claims, damages or liabilities and amounts paid in settlement in connection with any actual or threatened Proceeding, and provide advancement of expenses with respect to each of the foregoing to, all Indemnified Persons to the fullest extent permitted under applicable Law and (ii) honor the provisions regarding elimination of liability of officers and directors, indemnification of officers, directors and employees and advancement of expenses contained in the Organizational Documents of the Partnership and the Partnership GP immediately prior to the Effective Time and ensure that the Organizational Documents of the Surviving

 

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Entity and the Partnership GP or any of their respective successors or assigns, if applicable, shall, for a period of six years following the Effective Time, contain provisions no less favorable with respect to indemnification, advancement of expenses and exculpation of present and former directors, officers, employees and agents of the Partnership and the Partnership GP than are presently set forth in such Organizational Documents. Any right of an Indemnified Person pursuant to this Section 6.7(a) shall not be amended, repealed, terminated or otherwise modified at any time in a manner that would adversely affect the rights of such Indemnified Person as provided herein, and shall be enforceable by such Indemnified Person and their respective heirs and representatives against the Surviving Entity and the Partnership GP and their respective successors and assigns.

(b) The Surviving Entity shall maintain in effect for six years from the Effective Time the Partnership’s current directors’ and officers’ liability insurance policies covering acts or omissions occurring at or prior to the Effective Time with respect to Indemnified Persons (provided that the Surviving Entity may substitute therefor policies with reputable carriers of at least the same coverage containing terms and conditions that are no less favorable to the Indemnified Persons); provided, however, that in no event shall the Surviving Entity be required to expend pursuant to this Section 6.7(b) more than an amount per year equal to 300% of current annual premiums paid by the Partnership for such insurance (the “Maximum Amount”). In the event that, but for the proviso to the immediately preceding sentence, the Surviving Entity would be required to expend more than the Maximum Amount, the Surviving Entity shall obtain the maximum amount of such insurance as is available for the Maximum Amount. If the Partnership in its sole discretion elects, then, in lieu of the obligations of the Surviving Entity under this Section 6.7(b), the Partnership may (but shall be under no obligation to), prior to the Effective Time, purchase a “tail policy” with respect to acts or omissions occurring or alleged to have occurred prior to the Effective Time that were committed or alleged to have been committed by such Indemnified Persons in their capacity as such.

(c) The rights of any Indemnified Person under this Section 6.7 shall be in addition to any other rights such Indemnified Person may have under the Organizational Documents of the Partnership and the Partnership GP or any indemnification agreements. The provisions of this Section 6.7 shall survive the consummation of the transactions contemplated hereby for a period of six years and are expressly intended to benefit each of the Indemnified Persons and their respective heirs and representatives; provided, however, that in the event that any claim or claims for indemnification or advancement set forth in this Section 6.7 are asserted or made within such six-year period, all rights to indemnification and advancement in respect of any such claim or claims shall continue until disposition of all such claims. If the Surviving Entity and/or the Partnership GP, or any of their respective successors or assigns (i) consolidates with or merges into any other Person, or (ii) transfers or conveys all or substantially all of their businesses or assets to any other Person, then, in each such case, to the extent necessary, a proper provision shall be made so that the successors and assigns of the Surviving Entity or the Partnership GP shall assume the obligations of the Surviving Entity and the Partnership GP set forth in this Section 6.7.

Section 6.8 Fees and Expenses. Except as otherwise provided in Section 8.2, all fees and expenses incurred in connection with the transactions contemplated hereby including all legal, accounting, financial advisory, consulting and all other fees and expenses of third parties incurred by a party in connection with the negotiation and effectuation of the terms and conditions of this Agreement and the transactions contemplated hereby, shall be the obligation of the respective party incurring such fees and expenses, except Parent and the Partnership shall each bear and pay one half of the expenses, other than the expenses of financial advisors or outside legal advisors, incurred in connection with the preparation, printing, filing and mailing of the Partnership Information Statement and Schedule 13E-3.

Section 6.9 Section 16 Matters. Prior to the Effective Time, the Partnership and Partnership GP shall, with Parent’s and Merger Sub’s cooperation, take all such steps as may be required (to the extent permitted under applicable Law) to cause any dispositions of Units (including derivative securities with respect to Units) resulting from the transactions contemplated hereby by each individual who is subject to the reporting requirements of Section 16(a) of the Exchange Act with respect to the Partnership to be exempt under Rule 16b-3 promulgated under the Exchange Act.

 

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Section 6.10 Termination of Trading and Deregistration. The Partnership will cooperate with Parent and use reasonable best efforts to take, or cause to be taken, all actions and all things, reasonably necessary, proper or advisable on its part under applicable Laws and rules and policies of the NYSE to enable (a) the delisting of the Class A Common Units from the NYSE and the termination of trading of the Class A Common Units on the Closing Date and prior to the Effective Time and (b) the deregistration of the Class A Common Units under the Exchange Act as promptly as practicable after the Effective Time, and in any event no more than ten days after the Closing Date.

Section 6.11 GP Conflicts Committee. Prior to the earlier of the Effective Time and the termination of this Agreement, Parent shall not and it shall not permit any of its Subsidiaries to, and it shall not and shall not permit any of its Subsidiaries to take any action intended to cause the Partnership GP to, without the consent of a majority of the then existing members of the GP Conflicts Committee, eliminate the GP Conflicts Committee, revoke or diminish the authority of the GP Conflicts Committee or remove or cause the removal of any director of the Partnership GP that is a member of the GP Conflicts Committee either as a director or as a member of such committee. For the avoidance of doubt, this Section 6.11 shall not apply to the filling, in accordance with the provisions of the Partnership GP LLC Agreement, of any vacancies caused by the resignation, death or incapacity of any such director.

Section 6.12 Performance by the Partnership GP. The Partnership GP shall cause the Partnership and its Subsidiaries to comply with the provisions of this Agreement. Notwithstanding the foregoing, it is understood and agreed that actions or inactions by the Partnership, the Partnership GP and their respective Subsidiaries shall not be deemed to be breaches or violations or failures to perform by the Partnership, the Partnership GP and their respective Subsidiaries of any of the provisions of this Agreement if such action or inaction was or was not taken, as applicable, at the direction of Parent, its Affiliates or their respective Representatives.

Section 6.13 Takeover Statutes. The Partnership, the Partnership GP and Parent shall each use reasonable best efforts to (a) take all action necessary to ensure that no Takeover Statute is or becomes applicable to any of the transactions contemplated hereby and (b) if any Takeover Statute becomes applicable to any of the transactions contemplated hereby, take all action necessary to ensure that such transaction may be consummated as promptly as practicable on the terms contemplated hereby and otherwise minimize the effect of such Takeover Statute on the transaction.

Section 6.14 No Rights Triggered. The Partnership and the Partnership GP shall take all steps necessary to ensure that the entering into of this Agreement, the Merger and the other transactions contemplated hereby or related hereto and any other action or combination of actions do not and will not result in the grant of any Rights to any Person under the Partnership Agreement or under any material agreement to which the Partnership or any of its Subsidiaries is a party.

Section 6.15 Notification of Certain Matters. Each of the Partnership, the Partnership GP and Parent shall give prompt notice to the other of (a) any fact, event or circumstance known to it that (i) could reasonably be expected to, individually or taken together with all other facts, events and circumstances known to it, result in any Partnership Material Adverse Effect or prevent, materially delay or impair the ability of such party to consummate the Merger or comply with its respective obligations under this Agreement or (ii) could cause or constitute a material breach of any of its representations, warranties, covenants or agreements contained herein, and (b) (i) any change in the Partnership’s financial condition or business that results in, or could reasonably be expected to result in, a Partnership Material Adverse Effect or (ii) any Proceedings, to the extent such Proceedings relate to this Agreement or the Merger or could result in a Partnership Material Adverse Effect.

Section 6.16 Transaction Litigation. The Partnership shall give Parent the opportunity to participate in the defense or settlement of any security holder litigation against the Partnership, the Partnership GP or their respective directors relating to the Merger and the other transactions contemplated hereby, and no such settlement shall be agreed to without the prior written consent of Parent, which consent shall not be unreasonably withheld, conditioned or delayed.

 

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Section 6.17 Distributions. The Partnership GP shall declare, and shall cause the Partnership to pay, the Partnership’s regular quarterly cash distribution to holders of the Class A Common Units with respect to the quarter ended December 31, 2016 in accordance with the Partnership Agreement (the “Fourth Quarter Distribution”); provided, however, that, subject to applicable Laws, the Fourth Quarter Distribution shall not be less than $0.3575 without the prior approval of the GP Conflicts Committee. The Partnership and Parent shall coordinate the timing of the Fourth Quarter Distribution so that the record date and payment date precedes the Effective Time so as to permit the payment of the Fourth Quarter Distribution.

Section 6.18 Tax Matters.

(a) For U.S. federal income Tax purposes (and for purposes of any applicable state, local or foreign Tax that follows the U.S. federal income Tax treatment), the parties agree to treat the Merger (a) with respect to the Partnership Unaffiliated Unitholders, as a taxable sale of their Class A Common Units to Parent and (b) with respect to Parent, as a purchase from the Partnership Unaffiliated Unitholders of such Class A Common Units. The parties will prepare and file all Tax Returns consistent with the foregoing and will not take any inconsistent position on any Tax Return, or during the course of any audit, litigation or other proceeding with respect to Taxes, except as otherwise required by applicable Law following a final determination by a court of competent jurisdiction or other administrative settlement with or final administrative decision by the relevant Governmental Authority.

(b) The parties expect that the Merger will not result in the Partnership being treated as terminated under Section 708(b)(1)(B) of the Code. The parties shall not (and shall cause their Affiliates not to) make any change in respect of the Partnership’s methods of allocating income or deductions for federal income Tax purposes that would adversely affect the Partnership Unaffiliated Unitholders, including a change to the method of allocation prescribed under Section 6.2(f) of the Partnership Agreement.

ARTICLE VII.

CONDITIONS PRECEDENT

Section 7.1 Conditions to Each Party’s Obligation to Effect the Merger. The respective obligations of each party hereto to effect the Merger shall be subject to the satisfaction (or waiver, if permissible under applicable Law) on or prior to the Closing Date of the following conditions:

(a) Unitholder Approval. The affirmative vote or consent in favor of the approval of this Agreement, including the Merger, of the holders of a Unit Majority (the “Partnership Unitholder Approval”) shall have been obtained in accordance with applicable Law and the Organizational Documents of the Partnership.

(b) No Injunctions or Restraints. No Law, injunction, judgment or ruling enacted, promulgated, issued, entered, amended or enforced by any Governmental Authority (collectively, “Restraints”) shall be in effect enjoining, restraining, preventing or prohibiting consummation of the transactions contemplated hereby or making the consummation of the transactions contemplated hereby illegal.

Section 7.2 Conditions to Obligations of Parent and Merger Sub to Effect the Merger. The obligations of Parent and Merger Sub to effect the Merger are further subject to the satisfaction (or waiver, if permissible under applicable Law) on or prior to the Closing Date of the following conditions:

(a) Representations and Warranties. The representations and warranties of the Partnership and the Partnership GP qualified as to materiality or Partnership Material Adverse Effect set forth herein shall be true and correct in all respects, and those not so qualified shall be true and correct in all material respects, as of the Closing Date, as if made at and as of such time (except to the extent expressly made as of an earlier date, in which case as of such date). Parent shall have received a certificate signed on behalf of the Partnership and the Partnership GP by an executive officer of the Partnership GP to such effect.

 

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(b) Performance of Obligations of the Partnership and Partnership GP. Each of the Partnership and the Partnership GP shall have performed in all material respects all covenants and obligations required to be performed by it under this Agreement at or prior to the Closing Date. Parent shall have received a certificate signed on behalf of the Partnership and the Partnership GP by an executive officer of the Partnership GP to such effect.

Section 7.3 Conditions to Obligation of the Partnership to Effect the Merger. The obligation of the Partnership to effect the Merger is further subject to the satisfaction (or waiver, if permissible under applicable Law) on or prior to the Closing Date of the following conditions:

(a) Representations and Warranties. The representations and warranties of Parent and Merger Sub qualified as to materiality or Material Adverse Effect set forth herein shall be true and correct in all respects, and those not so qualified shall be true and correct in all material respects, as of the Closing Date, as if made at and as of such time (except to the extent expressly made as of an earlier date, in which case as of such date). The Partnership shall have received a certificate signed on behalf of Parent by an executive officer of Parent to such effect.

(b) Performance of Obligations of Parent and Merger Sub. Each of Parent and Merger Sub shall have performed in all material respects all covenants and obligations required to be performed by it under this Agreement at or prior to the Closing Date. The Partnership shall have received a certificate signed on behalf of Parent by an executive officer of Parent to such effect.

(c) No Partnership Material Adverse Effect. Since the date of this Agreement, no Partnership Material Adverse Effect shall have occurred.

Section 7.4 Frustration of Closing Conditions.

(a) Neither the Partnership nor the Partnership GP may rely on the failure of any condition set forth in Section 7.1, Section 7.2 or Section 7.3, as the case may be, to be satisfied if such failure was due to the failure of either such party to perform and comply in all material respects with the covenants and agreements to be performed or complied with by it prior to the Closing.

(b) Neither Parent nor Merger Sub may rely on the failure of any condition set forth in Section 7.1, Section 7.2 or Section 7.3, as the case may be, to be satisfied if such failure was due to the failure of either such party to perform and comply in all material respects with the covenants and agreements to be performed or complied with by it prior to the Closing.

ARTICLE VIII.

TERMINATION

Section 8.1 Termination. This Agreement may be terminated and the transactions contemplated hereby abandoned at any time prior to the Effective Time:

(a) by the mutual written consent of the Partnership and Parent duly authorized by the Parent Board and the GP Board, after consulting with the GP Conflicts Committee.

(b) by either of the Partnership (duly authorized by the GP Board after consulting with the GP Conflicts Committee) or Parent:

(i) if the Closing shall not have been consummated on or before June 30, 2017 (the “Outside Date”); provided, however, that the right to terminate this Agreement under this Section 8.1(b)(i) shall not be

 

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available to (A) the Partnership if the failure to satisfy such condition was due to the failure of the Partnership or the Partnership GP to perform and comply in all material respects with the covenants and agreements contained in this Agreement to be performed or complied with by it prior to the Closing, (B) Parent if the failure to satisfy such condition was due to the failure of the Parent, Merger Sub or EEP to perform and comply in all material respects with the covenants and agreements contained in this Agreement or the EEP Support Agreement, as applicable, to be performed or complied with by it prior to the Closing or (C) the Partnership or Parent if in the case of Parent, the Partnership or the Partnership GP, and in the case of the Partnership, Parent or Merger Sub, has filed (and is then pursuing) an action seeking specific performance as permitted by Section 9.8;

(ii) if any Restraint having the effect set forth in Section 7.1(b) shall be in effect and shall have become final and nonappealable; provided, however, that the right to terminate this Agreement under this Section 8.1(b)(ii) shall not be available to the Partnership or Parent if such Restraint was due to the failure of, in the case of the Partnership, the Partnership or the Partnership GP and in the case of Parent, Parent, Merger Sub or EEP, to perform in all material respects any of its obligations under this Agreement or the EEP Support Agreement, as applicable; or.

(iii) if a Partnership Adverse Recommendation Change shall have occurred.

(c) by Parent:

(i) if prior to obtaining the Partnership Unitholder Approval, if the Partnership is in willful breach of its obligations pursuant to the first two sentences of Section 6.1(b) or Section 6.3(a); provided that Parent shall not have the right to terminate this Agreement pursuant to this Section 8.1(c)(i) if Parent, Merger Sub or EEP is then in material breach of any of its representations, warranties, covenants or agreements contained in this Agreement or the EEP Support Agreement, as applicable; or

(ii) if the Partnership or the Partnership GP shall have breached or failed to perform any of its representations, warranties, covenants or agreements set forth in this Agreement (or if any of the representations or warranties of the Partnership or the Partnership GP set forth in this Agreement shall fail to be true), which breach or failure (A) would (if it occurred or was continuing as of the Closing Date) give rise to the failure of a condition set forth in Section 7.2(a) or Section 7.2(b) and (B) is incapable of being cured, or is not cured, by the Partnership or the Partnership GP within the earlier of (x) 30 days following receipt of written notice from Parent of such breach or failure or (y) the Outside Date; provided, however, that Parent shall not have the right to terminate this Agreement pursuant to this Section 8.1(c)(ii) if Parent, Merger Sub or EEP is then in material breach of any of its representations, warranties, covenants or agreements contained in this Agreement or the EEP Support Agreement, as applicable.

(d) by the Partnership (duly authorized by the GP Board after consulting with the GP Conflicts Committee) if Parent or Merger Sub shall have breached or failed to perform any of its representations, warranties, covenants or agreements set forth in this Agreement (or if any of the representations or warranties of Parent or Merger Sub set forth in this Agreement shall fail to be true), which breach or failure (A) would (if it occurred or was continuing as of the Closing Date) give rise to the failure of a condition set forth in Section 7.3(a) or Section 7.3(b) and (B) is incapable of being cured, or is not cured, by Parent or Merger Sub within the earlier of (x) 30 days following receipt of written notice from the Partnership of such breach or failure or (y) the Outside Date; provided, however, that the Partnership shall not have the right to terminate this Agreement pursuant to this Section 8.1(d) if the Partnership or the Partnership GP is then in material breach of any of its representations, warranties, covenants or agreements contained in this Agreement.

Section 8.2 Effect of Termination. In the event of the termination of this Agreement as provided in Section 8.1, written notice thereof shall be given to the other party or parties, specifying the provision of this Agreement pursuant to which such termination is made, and this Agreement shall forthwith become null and void (other than the provisions in Section 6.8, Section 6.16, Section 8.2 and Article IX, all of which shall survive termination of this Agreement), and, except as otherwise provided in this Section 8.2, there shall be no liability

 

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on the part of any of Parent, Merger Sub or the Partnership and the Partnership GP or their respective directors, officers and Affiliates, provided, however, that no such termination shall relieve any party hereto from any liability for any failure to consummate the Merger and the other transactions contemplated hereby when required pursuant to this Agreement; provided, however, that in the event of a party’s intentional and material breach of this Agreement or intentional fraud, then the other applicable party or parties shall be entitled to pursue any and all legally available remedies, including equitable relief, and to seek recovery of all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees and time value of money). For the avoidance of doubt, there shall be no liability on the part of the Partnership GP or the Partnership or their respective directors, officers and Affiliates if this Agreement is terminated by Parent or the Partnership pursuant to Section 8.1(b)(iii). Notwithstanding the foregoing, in no event shall the Partnership GP or the Partnership or their respective directors, officers and Affiliates have any liability for any matter set forth in the proviso of the first sentence of this Section 8.2 for any action taken or omitted to be taken by the Partnership GP, the Partnership, any of their respective Subsidiaries or any of their respective Representatives at the direction of Parent, any of its Subsidiaries or any of their respective Representatives.

ARTICLE IX.

MISCELLANEOUS

Section 9.1 No Survival, Etc.. The representations, warranties and agreements in this Agreement (including, for the avoidance of doubt, any schedule, instrument or other document delivered pursuant to this Agreement) shall terminate at the Effective Time or, except as otherwise provided in Section 8.2, upon the termination of this Agreement pursuant to Section 8.1, as the case may be, except that the agreements set forth in Article I, Article II, Article III, Section 6.7, Section 6.8, Section 6.16 and Section 6.18 and any other agreement in this Agreement that contemplates performance after the Effective Time shall survive the Effective Time.

Section 9.2 Amendment or Supplement. At any time prior to the Effective Time, this Agreement may be amended or supplemented in any and all respects, whether before or after obtaining the Partnership Unitholder Approval, by written agreement of the parties hereto, by action taken or authorized by the Parent Board and the GP Board; provided, however, that this Agreement may not be amended, modified or supplemented without the prior approval of the GP Conflicts Committee; provided, further, that after obtaining the Partnership Unitholder Approval, there shall be no amendment or change to the provisions of this Agreement which by applicable Law or stock exchange rule would require further approval by the Limited Partners without such approval. Unless otherwise expressly set forth in this Agreement, whenever a determination, decision, approval, consent, waiver or agreement of the Partnership or Partnership GP is required pursuant to this Agreement (including any determination to exercise or refrain from exercising any rights under Article VIII or to enforce the terms of this Agreement (including Section 9.8)), such determination, decision, approval, consent, waiver or agreement must be authorized by the GP Conflicts Committee and such action shall not require approval of the holders of Class A Common Units.

Section 9.3 Extension of Time, Waiver, Etc. At any time prior to the Effective Time, any party may, subject to applicable Law, (a) waive any inaccuracies in the representations and warranties of any other party hereto, (b) extend the time for the performance of any of the obligations or acts of any other party hereto, (c) waive compliance by any other party hereto with any of the agreements contained herein or, except as otherwise provided herein, waive any of such party’s conditions or (d) make or grant any consent under this Agreement; provided, however, that neither the Partnership nor the Partnership GP shall take or authorize any such action without the prior approval of the GP Board (after consulting with the GP Conflicts Committee). Notwithstanding the foregoing, no failure or delay by the Partnership, the Partnership GP, Parent or Merger Sub in exercising any right hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right hereunder. Any agreement on the part of a party hereto to any such extension or waiver shall be valid only if set forth in an instrument in writing signed on behalf of such party.

 

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Section 9.4 Assignment. Neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned, in whole or in part, by operation of Law or otherwise, by any of the parties without the prior written consent of the other parties, except that Parent or Merger Sub may assign, in its sole discretion, any of or all its rights, interests and obligations under this Agreement to any Subsidiary of Parent, but no such assignment shall relieve Parent or Merger Sub of any of its obligations hereunder. Subject to the preceding sentence, this Agreement shall be binding upon, inure to the benefit of, and be enforceable by, the parties hereto and their respective successors and permitted assigns. Any purported assignment not permitted under this Section 9.4 shall be null and void.

Section 9.5 Counterparts. This Agreement may be executed in counterparts (each of which shall be deemed to be an original but all of which taken together shall constitute one and the same agreement) and shall become effective when one or more counterparts have been signed by each of the parties and delivered to the other parties. Signatures to this Agreement transmitted by facsimile transmission, by electronic mail in “portable document format” (“.pdf”) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, will have the same effect as physical delivery of the paper document bearing the original signature.

Section 9.6 Entire Understanding; No Third-Party Beneficiaries. This Agreement and any certificates delivered by any party pursuant to this Agreement (a) constitute the entire agreement and understanding, and supersede all other prior agreements and understandings, both written and oral, among the parties with respect to the subject matter of this Agreement and thereof and (b) shall not confer upon any Person other than the parties hereto any rights (including third-party beneficiary rights or otherwise) or remedies hereunder, except for, in the case of clause (b), (i) the provisions of Section 6.7 and Section 9.11 and (ii) subject to Sections 3.1(d) and (f) and Section 3.4, the right of the holders of Class A Common Units to receive the Merger Consideration after the Closing (a claim by the holders of Class A Common Units with respect to which may not be made unless and until the Closing shall have occurred). Notwithstanding anything to the contrary in this Agreement, Section 9.11 shall be for the benefit of, and enforceable by, any financing sources or lender providing financing in connection with the Merger. Any inaccuracies in the representations and warranties set forth in this Agreement are subject to waiver by the parties hereto in accordance with Section 9.3 without notice or liability to any other Person. In some instances, the representations and warranties in this Agreement may represent an allocation among the parties hereto of risks associated with particular matters regardless of the Knowledge of any of the parties hereto. Consequently, Persons other than the parties hereto may not rely upon the representations and warranties in this Agreement as characterizations of actual facts or circumstances as of the date of this Agreement or as of any other date.

Section 9.7 Governing Law; Jurisdiction; Waiver of Jury Trial.

(a) This Agreement shall be governed by, and construed in accordance with, the Laws of the State of Delaware, applicable to contracts executed in and to be performed entirely within that State, regardless of the Law that might otherwise govern under applicable principles of conflicts of Law thereof. Each of the parties hereto irrevocably agrees that any legal action or Proceeding with respect to this Agreement and the rights and obligations arising hereunder, shall be brought and determined exclusively in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware). Each of the parties hereto consents to service of process being made upon it through the notice procedures set forth in Section 9.9, irrevocably submits with regard to any such action or Proceeding for itself and in respect of its property, generally and unconditionally, to the personal jurisdiction of the aforesaid courts and agrees that it will not bring any action relating to this Agreement or any of the transactions contemplated hereby in any court other than the aforesaid courts. Each of the parties hereto irrevocably waives, and agrees not to assert as a defense, counterclaim or otherwise, in any action or Proceeding with respect to this Agreement, (i) any claim that it is not personally subject to the jurisdiction of the above named courts for any reason other than the failure to serve in accordance with this Section 9.7, (ii) any claim that it or its property is exempt or immune from the

 

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jurisdiction of any such court or from any legal process commenced in such courts (whether through service of notice, attachment prior to judgment, attachment in aid of execution of judgment, execution of judgment or otherwise) and (iii) to the fullest extent permitted by the applicable Law, any claim that (A) the suit, action or Proceeding in such court is brought in an inconvenient forum, (B) the venue of such suit, action or Proceeding is improper or (C) this Agreement, or the subject matter hereof, may not be enforced in or by such courts. Each party hereto expressly acknowledges that the foregoing waiver is intended to be irrevocable under the Law of the State of Delaware and of the United States of America; provided, however, that each such party’s consent to jurisdiction and service contained in this Section 9.7(a) is solely for the purposes referred to in this Section 9.7(a) and shall not be deemed to be a general submission to such courts or in the State of Delaware other than for such purposes.

(b) EACH PARTY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THE ACTIONS OF ANY PARTY IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE AND ENFORCEMENT OF THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 9.8 Specific Performance. Each of the parties agrees that irreparable damage would occur and that the parties would not have any adequate remedy at law in the event that any of the provisions of this Agreement were not performed (including failing to take such actions as are required of it hereunder in order to consummate the Merger) in accordance with their specific terms or were otherwise breached and it is accordingly agreed that the parties shall be entitled to seek an injunction or injunctions to prevent breaches of this Agreement and to enforce specifically the terms and provisions of this Agreement, in each case, in accordance with this Section 9.8 in the Delaware Court of Chancery (or, if the Delaware Court of Chancery declines to accept personal jurisdiction, any federal court sitting in the State of Delaware), this being in addition to any other remedy to which they are entitled at law or in equity. Each of the parties agrees that it will not oppose the granting of an injunction, specific performance and other equitable relief as provided herein on the basis that (a) either party has an adequate remedy at law or (b) an award of specific performance is not an appropriate remedy for any reason at law or equity (it being understood that nothing in this sentence shall prohibit the parties hereto from raising other defenses to a claim for specific performance or other equitable relief under this Agreement). Each party further agrees that no party shall be required to obtain, furnish or post any bond or similar instrument in connection with or as a condition to obtaining any remedy referred to in this Section 9.8, and each party irrevocably waives any right it may have to require the obtaining, furnishing or posting of any such bond or similar instrument.

Section 9.9 Notices. All notices and other communications hereunder must be in writing and will be deemed duly given if delivered personally or by facsimile transmission, or mailed through a nationally recognized overnight courier or registered or certified mail (return receipt requested), postage prepaid, to the parties at the following addresses (or at such other address for a party as specified by like notice, provided, however, that notices of a change of address will be effective only upon receipt thereof):

If to Parent or Merger Sub, to:

Enbridge Energy Company, Inc.

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

Attention: Mark Boyce

Facsimile: 713-821-2229

 

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with copies (which shall not constitute notice) to:

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Attention: Brett E. Braden

Email: brett.braden@lw.com

and

Enbridge Energy Partners, L.P.

c/o Enbridge Energy Management, L.L.C.

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

Attention: Lisa Wilson

Facsimile: 713-821-2229

Email: lisa.wilson@enbridge.com

and

EEP GP Delegate Conflicts Committee

c/o Enbridge Energy Management, L.L.C.

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

Attention: Chairman of the Conflicts Committee

Facsimile: 713-821-2229

and

Vinson & Elkins LLP

1001 Fannin Street, Suite 2500

Houston, Texas 77002

Attention: Michael Telle

Email: mtelle@velaw.com

If to the Partnership or the Partnership GP, to:

Midcoast Energy Partners, L.P.

c/o Midcoast Holdings, L.L.C.

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

Attention: Chris Kaitson

Facsimile: 713-821-2229

Email: chris.kaitson@enbridge.com

with copies (which shall not constitute notice) to:

GP Conflicts Committee

c/o Midcoast Holdings, L.L.C.

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

Attention: Chairman of the Conflicts Committee

Facsimile: 713-821-2229

 

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and

Bracewell LLP

711 Louisiana Street, Suite 2300

Houston, Texas 77002

Attention: Will Anderson

Email: will.anderson@bracewelllaw.com

Notices will be deemed to have been received (x) on the date of receipt if (i) delivered by hand or nationally recognized overnight courier service or (ii) upon receipt of an appropriate electronic answerback or confirmation when so delivered by fax (to such number specified above or another number or numbers as such Person may subsequently designate by notice given hereunder only if followed by overnight or hand delivery) or (y) on the date five Business Days after dispatch by certified or registered mail.

Section 9.10 Severability. If any term or other provision of this Agreement is determined by a court of competent jurisdiction to be invalid, illegal or incapable of being enforced by any rule of law or public policy, all other terms, provisions and conditions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner adverse to any party hereto. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible to the fullest extent permitted by applicable Law in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

Section 9.11 Non-Recourse. No past, present or future director, officer, employee, incorporator, member, partner, stockholder, financing source, lender, agent, attorney, representative or affiliate of any party hereto or of any of their respective Affiliates shall have any liability (whether in contract or in tort or otherwise) for any obligations or liabilities arising under, in connection with or related to this Agreement or for any claim based on, in respect of, or by reason of, the transactions contemplated hereby; provided, however, that nothing in this Section 9.11 shall limit any liability of the parties to this Agreement and the EEP Support Agreement for breaches of the representations, warranties, covenants and agreements contained in this Agreement and the EEP Support Agreement.

[Signature page follows]

 

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered as of the date first above written.

 

PARENT:
ENBRIDGE ENERGY COMPANY, INC.
By:  

/s/ NOOR S. KAISSI

Name:   Noor S. Kaissi
Title:   Controller

 

MERGER SUB:
ENBRIDGE HOLDINGS (LEATHER) L.L.C.
By:  

/s/ NOOR S. KAISSI

Name:   Noor S. Kaissi
Title:   Controller

 

[Signature Page to Merger Agreement]

 

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PARTNERSHIP:
MIDCOAST ENERGY PARTNERS L.P.
By: Midcoast Holding, L.L.C., its general partner
By:  

/s/ C. GREGORY HARPER

Name:   C. Gregory Harper
Title:   President

 

PARTNERSHIP GP:
Midcoast Holdings, L.L.C.
By:  

/s/ C. GREGORY HARPER

Name:   C. Gregory Harper
Title:   President

 

 

[Signature Page to Merger Agreement]

 

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ANNEX B

Execution Version

 

 

 

SUPPORT AGREEMENT

BY AND AMONG

ENBRIDGE ENERGY PARTNERS, L.P.,

ENBRIDGE ENERGY COMPANY, INC.

AND

MIDCOAST ENERGY PARTNERS, L.P.

DATED AS OF JANUARY 26, 2017

 

 

 

 

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SUPPORT AGREEMENT

This SUPPORT AGREEMENT, dated as of January 26, 2017 (this “Agreement”), is by and among MIDCOAST ENERGY PARTNERS, L.P., a Delaware limited partnership (“MEP”), ENBRIDGE ENERGY COMPANY, INC., a Delaware corporation (“EECI”), and ENBRIDGE ENERGY PARTNERS, L.P., a Delaware limited partnership (“EEP”).

W I T N E S S E T H:

WHEREAS, concurrently with the execution of this Agreement, EECI, Enbridge Holdings (Leather) L.L.C., a Delaware limited liability company and wholly-owned Subsidiary of EECI (“Merger Sub”), MEP and Midcoast Holdings, L.L.C., a Delaware limited liability company and the general partner of MEP (“MEP GP”), are entering into an Agreement and Plan of Merger, dated as of the date hereof (as amended, supplemented, restated or otherwise modified from time to time, the “Merger Agreement”), pursuant to which, among other things, Merger Sub will merge with and into MEP (the “Merger”), with MEP as the surviving entity, and each outstanding Class A Common Unit will be converted into the right to receive the merger consideration specified therein, other than (i) Class A Common Units owned by MEP, any of its Subsidiaries, Parent or its Affiliates (other than EEP), which shall be cancelled and cease to exist and (ii) Class A Common Units owned by EEP, which shall be unchanged and remain issued and outstanding;

WHEREAS, as of the date hereof, EEP is the record owner in the aggregate of, and has the right to vote and dispose of, 1,335,056 Common Units and EEP is the record owner in the aggregate of 22,610,056 Subordinated Units (such Common Units and Subordinated Units, together, the “Existing Units”); and

WHEREAS, as an inducement and condition of EECI’s willingness to enter into the Merger Agreement and to consummate the transactions contemplated thereby, EECI has required that EEP, and EEP has agreed to, enter into this Agreement and abide by the covenants and obligations with respect to the Covered Units (as hereinafter defined), set forth herein.

NOW THEREFORE, in consideration of the foregoing and the mutual representations, warranties, covenants and agreements herein contained, and intending to be legally bound hereby, the parties hereto agree as follows:

ARTICLE 1

GENERAL

Section 1.1 Defined Terms. The following capitalized terms, as used in this Agreement, shall have the meanings set forth below. Capitalized terms used but not otherwise defined herein shall have the meanings ascribed thereto in the Merger Agreement.

Agreement” has the meaning assigned to such term in the preamble.

Affiliate” or “Affiliates” has the meaning set forth in the Merger Agreement.

Business Day” has the meaning set forth in the Merger Agreement.

Class A Common Units” has the meaning set forth in the Partnership Agreement.

Common Units” has the meaning set forth in the Partnership Agreement.

 

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Covered Units” means the Existing Units together with any Common Units that EEP or any of its Subsidiaries acquires beneficially or of record on or after the date hereof.

EECI” has the meaning assigned to such term in the preamble.

EEP” has the meaning assigned to such term in the preamble.

EEP Unaffiliated Unitholders” means the holders of units of limited partner interest in EEP other than Parent, EEP GP Delegate and their respective Affiliates.

EEP GP Delegate” means Enbridge Energy Management, L.L.C., as the delegate of EECI, the general partner of EEP.

EEP GP Delegate Board” means the Board of Directors of the EEP GP Delegate.

EEP GP Delegate Conflicts Committee” has the meaning assigned to such term in Section 3.2(a)(ii).

Effective Time” has the meaning set forth in the Merger Agreement.

Existing Units” has the meaning assigned to such term in the recitals.

Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder.

GP Board” has the meaning set forth in the Merger Agreement.

GP Conflicts Committee” has the meaning set forth in the Merger Agreement.

Lien” means any mortgage, lien, charge, restriction (including restrictions on transfer), pledge, security interest, option, right of first offer or refusal, preemptive right, put or call option, lease or sublease, claim, right of any third party, covenant, right of way, easement, encroachment or encumbrance.

MEP” has the meaning assigned to such term in the preamble.

MEP GP” has the meaning assigned to such term in the recitals.

Merger” has the meaning assigned to such term in the recitals.

Merger Agreement” has the meaning assigned to such term in the recitals.

Merger Consideration” has the meaning set forth in the Merger Agreement.

Merger Sub” has the meaning assigned to such term in the recitals.

OrderorOrders” has the meaning set forth in Section 3.1(d) of this Agreement.

Partnership Adverse Recommendation Change” has the meaning set forth in the Merger Agreement.

Partnership Agreement” means the First Amended and Restated Agreement of Limited Partnership of the Partnership dated as of November 13, 2013, as amended, modified or supplemented from time to time.

Partnership Information Statement” has the meaning set forth in the Merger Agreement.

 

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Partnership Interest” has the meaning set forth in the Partnership Agreement.

Person” means any individual, corporation, limited liability company, limited or general partnership, joint venture, association, joint stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity, or any group comprised of two or more of the foregoing.

Representative” or “Representatives” has the meaning set forth in the Merger Agreement.

Subordinated Units” has the meaning set forth in the Partnership Agreement.

Subsidiary” or “Subsidiaries” has the meaning set forth in the Merger Agreement.

Surviving Entity” has the meaning set forth in the Merger Agreement.

Termination Date” has the meaning set forth in Section 6.1 of this Agreement.

Transfer” means, directly or indirectly, to sell, transfer, assign or similarly dispose of (by merger (including by conversion into securities or other consideration), by tendering into any tender or exchange offer, by testamentary disposition, by operation of law or otherwise), either voluntarily or involuntarily, or to enter into any contract, option or other arrangement or understanding with respect to the voting of or sale, transfer, assignment or similar disposition of (by merger (including by conversion into securities or other consideration), by tendering into any tender or exchange offer, by testamentary disposition, by operation of law or otherwise); provided that, for purposes of clarification, a Transfer shall not include any existing or future pledges or security interests issued by EEP in connection with a bona fide loan or the conversion of any Covered Units pursuant to the terms of the Partnership Agreement (including, for the avoidance of doubt, the conversion of EEP’s Subordinated Units into Common Units).

ARTICLE 2

VOTING

Section 2.1 Agreement to Vote Covered Units.

(a) EEP hereby irrevocably and unconditionally agrees, in its capacity as a holder of the Covered Units, that prior to the Termination Date (as defined herein), at any meeting of the unitholders of MEP, however called, including any adjournment or postponement thereof, or in connection with any written consent of the unitholders of MEP, it shall, to the fullest extent that the Covered Units are entitled to vote thereon or consent thereto:

(i) appear at each such meeting or otherwise cause its Covered Units to be counted as present thereat for purposes of establishing a quorum; and

(ii) vote (or cause to be voted), in person or by proxy, or deliver (or cause to be delivered) a written consent covering, all of the Covered Units (A) in favor of the approval and adoption of the Merger Agreement, any transactions contemplated by the Merger Agreement and any other matter necessary for the consummation of such transactions submitted for the vote or written consent of the unitholders of MEP; (B) against any action or agreement that would result in a breach of any covenant, representation or warranty or any other obligation or agreement of MEP or MEP GP or any of their Subsidiaries contained in the Merger Agreement; and (C) against any action, agreement or transaction that would impede, interfere with, delay, postpone or adversely affect the Merger or the other transactions contemplated by the Merger Agreement.

(b) Except as otherwise set forth in or contemplated by this Agreement, EEP may vote the Covered Units in its discretion on all matters submitted for the vote of unitholders of MEP or in connection with any written consent of MEP’s unitholders in a manner that is not inconsistent with the terms of this Agreement.

 

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Section 2.2 No Inconsistent Agreements. EEP hereby represents, covenants and agrees that, except for this Agreement, it (a) has not entered into, and shall not enter into at any time while this Agreement remains in effect, any voting agreement or voting trust with respect to its Covered Units, (b) has not granted, and shall not grant at any time while this Agreement remains in effect, a proxy, consent or power of attorney with respect to its Covered Units and (c) has not taken and shall not knowingly take any action that would make any representation or warranty of EEP contained herein untrue or incorrect or have the effect of preventing or disabling EEP from performing any of its obligations under this Agreement.

ARTICLE 3

REPRESENTATIONS AND WARRANTIES

Section 3.1 Representations and Warranties of EEP. EEP (except to the extent otherwise provided herein) hereby represents and warrants to MEP and EECI as follows:

(a) Good Standing. EEP is a limited partnership duly formed, validly existing and in good standing under the laws of the jurisdiction of its organization.

(b) Organization; Authorization; Validity of Agreement; Necessary Action.

(i) EEP has the requisite power and authority and/or capacity to execute and deliver this Agreement, to carry out its obligations hereunder and to consummate the transactions contemplated hereby. The execution and delivery by EEP of this Agreement, the performance by it of the obligations hereunder and the consummation of the transactions contemplated hereby have been duly and validly authorized by EEP and no other actions or proceedings on the part of EEP to authorize the execution and delivery of this Agreement, the performance by it of the obligations hereunder or the consummation of the transactions contemplated hereby are required. This Agreement has been duly executed and delivered by EEP and, assuming the due authorization, execution and delivery of this Agreement by the other parties hereto, constitutes a legal, valid and binding agreement of EEP enforceable against it in accordance with its terms, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditors’ rights and to general equitable principles.

(ii) The Special Committee (the “EEP GP Delegate Conflicts Committee”) of the EEP GP Delegate Board, at a meeting duly called and held, has (A) determined that each of the Merger, the Merger Agreement and the transactions contemplated by the Merger Agreement is fair and reasonable to and in the best interests of EEP, including the EEP Unaffiliated Unitholders, (B) recommended that the EEP GP Delegate Board authorize and approve the voting or consent by EEP, (1) as the sole member of MEP GP and (2) of the Existing Units held by EEP, in favor of the Merger and adoption and approval of the Merger Agreement, and (C) recommended that the EEP GP Delegate Board authorize and approve this Agreement.

(iii) The EEP GP Delegate Board (acting in part based on the recommendation of the EEP GP Delegate Conflicts Committee) has (A) determined that each of the Merger, the Merger Agreement and the transactions contemplated by the Merger Agreement is fair and reasonable to and in the best interests of EEP, including its partners, (B) authorized and approved the voting or consent by EEP, (1) as the sole member of MEP GP and (2) of the Existing Units held by EEP, in favor of the Merger and adoption and approval of the Merger Agreement, and (C) authorized and approved this Agreement.

(c) Ownership. As of the date hereof, EEP is the record owner of the Existing Units, and all of the Covered Units owned by EEP from the date hereof through and on the Closing Date will be owned of record or beneficially by EEP. EEP has and will have at all times through the Closing Date voting power (including the right to control such vote as contemplated herein), power of disposition, power to issue instructions with respect to the matters set forth in Article 2 hereof, and power to agree to all of the matters set forth in this Agreement, in each case with respect to all of the Covered Units owned by EEP at all times through the Closing Date.

 

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(d) No Violation. Neither the execution and delivery of this Agreement by EEP nor the performance by EEP of its obligations under this Agreement will (i) result in a violation or breach of or conflict with any provisions of, or constitute a default (or an event which, with notice or lapse of time or both, would constitute a default) under, or result in the termination, cancellation of, or give rise to a right of purchase under, or accelerate the performance required by, or result in a right of termination or acceleration under, or result in the creation of any Lien upon any of the properties, rights or assets, including the Existing Units, owned by EEP, (ii) violate any judgments, decrees, injunctions, rulings, awards, settlements, stipulations or orders (collectively, “Orders”) or laws applicable to EEP or any of its properties, rights or assets or (iii) result in a violation or breach of or conflict with its organizational and governing documents.

(e) Consents and Approvals. No consent, approval, Order or authorization of, or registration, declaration or filing with, any governmental authority is necessary to be obtained or made by EEP in connection with EEP’s execution, delivery and performance of this Agreement or the consummation by EEP of the transactions contemplated hereby, except for any requirements under the Exchange Act in connection with this Agreement and the transactions contemplated hereby.

(f) Reliance by MEP and EECI. EEP understands and acknowledges that each of MEP and EECI is entering into the Merger Agreement in reliance upon the execution and delivery of this Agreement and the representations, warranties, covenants and obligations of EEP contained herein.

Section 3.2 Representations and Warranties of MEP. MEP (except to the extent otherwise provided herein) hereby represents and warrants to EEP and EECI as follows:

(a) Organization; Authorization; Validity of Agreement; Necessary Action. MEP has the requisite power and authority and/or capacity to execute and deliver this Agreement, to carry out its obligations hereunder and to consummate the transactions contemplated hereby. The execution and delivery by MEP of this Agreement, the performance by it of the obligations hereunder and the consummation of the transactions contemplated hereby have been duly and validly authorized by MEP and no other actions or proceedings on the part of MEP to authorize the execution and delivery of this Agreement, the performance by it of the obligations hereunder or the consummation of the transactions contemplated hereby are required. This Agreement has been duly executed and delivered by MEP and, assuming the due authorization, execution and delivery of this Agreement by the other parties hereto, constitutes a legal, valid and binding agreement of MEP enforceable against it in accordance with its terms, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditors’ rights and to general equitable principles.

(b) No Violation. Neither the execution and delivery of this Agreement by MEP nor the performance by MEP of its obligations under this Agreement will (i) result in a violation or breach of or conflict with any provisions of, or constitute a default (or an event which, with notice or lapse of time or both, would constitute a default) under, or result in the termination, cancellation of, or give rise to a right of purchase under, or accelerate the performance required by, or result in a right of termination or acceleration under, or result in the creation of any Lien upon any of the properties, rights or assets, owned by MEP, (ii) violate any Orders or laws applicable to MEP or any of its properties, rights or assets or (iii) result in a violation or breach of or conflict with its organizational and governing documents.

(c) Consents and Approvals. No consent, approval, Order or authorization of, or registration, declaration or filing with, any governmental authority is necessary to be obtained or made by MEP in connection with MEP’s execution, delivery and performance of this Agreement or the consummation by MEP of the transactions contemplated hereby, except for any requirements under the Exchange Act in connection with this Agreement and the transactions contemplated hereby.

Section 3.3 Representations and Warranties of EECI. EECI hereby represents and warrants to EEP and MEP that the execution and delivery of this Agreement by EECI and the consummation of the transactions contemplated hereby have been duly authorized by all necessary action on the part of EECI.

 

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ARTICLE 4

GRANT OF IRREVOCABLE PROXY; APPOINTMENT OF PROXY

Section 4.1 Grant of Irrevocable Proxy; Appointment of Proxy. FROM AND AFTER THE DATE HEREOF UNTIL THE TERMINATION DATE, EEP HEREBY IRREVOCABLY AND UNCONDITIONALLY GRANTS TO, AND APPOINTS, C. GREGORY HARPER, E. CHRIS KAITSON AND ANY OTHER PROXY DESIGNEE, EACH OF THEM INDIVIDUALLY, EEP’S PROXY AND ATTORNEY-IN-FACT (WITH FULL POWER OF SUBSTITUTION) TO VOTE (OR EXERCISE A WRITTEN CONSENT WITH RESPECT TO) THE COVERED UNITS SOLELY IN ACCORDANCE WITH ARTICLE 2, IF AND ONLY IF EEP FAILS TO VOTE OR ATTEMPTS TO VOTE THE COVERED UNITS IN A MANNER INCONSISTENT WITH THE TERMS OF THIS AGREEMENT. THIS PROXY IS IRREVOCABLE (UNTIL THE TERMINATION DATE AND EXCEPT AS TO ANY PROXY DESIGNEE WHOSE DESIGNATION AS A PROXY DESIGNEE IS REVOKED BY THE GP CONFLICTS COMMITTEE) AND COUPLED WITH AN INTEREST, AND EEP WILL TAKE SUCH FURTHER ACTION OR EXECUTE SUCH OTHER INSTRUMENTS AS MAY BE NECESSARY TO EFFECTUATE THE INTENT OF THIS PROXY AND HEREBY REVOKES ANY OTHER PROXY PREVIOUSLY GRANTED BY EEP WITH RESPECT TO THE COVERED UNITS TO VOTE ON THE MATTERS SET FORTH IN ARTICLE 2 HEREOF (AND EEP HEREBY REPRESENTS TO MEP THAT ANY SUCH OTHER PROXY IS REVOCABLE).

Section 4.2 Expiration of Proxy. The proxy granted in this Article 4 shall automatically expire upon the termination of this Agreement.

ARTICLE 5

OTHER COVENANTS

Section 5.1 Prohibition on Transfers, Other Actions. From and after the date hereof and until the Termination Date, EEP agrees not to (a) Transfer any of the Covered Units, beneficial ownership thereof or voting power therein; (b) enter into any agreement, arrangement or understanding, or take any other action, that violates or conflicts with or would reasonably be expected to violate or conflict with, or result in or give rise to a violation of or conflict with, EEP’s representations, warranties, covenants and obligations under this Agreement; or (c) take any action that would reasonably be expected to restrict or otherwise affect EEP’s legal power, authority and right to comply with and perform its covenants and obligations under this Agreement; provided, the foregoing shall not include or prohibit Transfers resulting from pledges or security interests (or the foreclosure thereof) relating to existing or future bona fide loans that do not affect EEP’s legal power, authority and right to comply with and perform its covenants and obligations under this Agreement. Notwithstanding anything to the contrary in this Agreement, EEP may Transfer any or all of the Covered Units, in accordance with applicable law, to any affiliate of EEP; provided, further, that prior to and as a condition to the effectiveness of such Transfer, each Person to whom any of such Covered Units or any interest in any of such Covered Units is or may be Transferred shall have executed and delivered to MEP and EECI a counterpart of this Agreement pursuant to which such Person shall be bound by all of the terms and provisions of this Agreement as if such Person were EEP. Any Transfer in violation of this provision shall be null and void.

Section 5.2 Unit Splits and Unit Distributions. In the event of a unit split, unit distribution or any change in the Units by reason of any split-up, reverse unit split, recapitalization, combination, reclassification, exchange or conversion of units or the like, the terms “Covered Units” and “Existing Units” shall be deemed to refer to and include such Units as well as all such distributions and any securities of MEP into which or for which any or all of such Units may be changed, exchanged or converted or which are received in such transaction.

Section 5.3 Unitholder Capacity. The parties hereto acknowledge that this Agreement is being entered into by EEP solely in its capacity as a holder of Covered Units, and nothing in this Agreement shall restrict or limit

 

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the ability of EEP or any officer, director, owner or employee thereof to take any action in his, her or its capacity as an officer, director, owner or employee thereof or MEP or MEP GP.

Section 5.4 Non-Survival of Representations and Warranties. The representations and warranties of the parties contained herein shall not survive the Termination Date.

Section 5.5 Further Assurances. From time to time, at MEP’s request and expense and without further consideration, EEP shall execute and deliver such additional documents and take all such further action as may be reasonably necessary or advisable to effect the actions and consummate the transactions contemplated by this Agreement.

Section 5.6 Rollover of Partnership Interests. EEP agrees and acknowledges that, in the Merger, the Partnership Interests of which EEP is the record and beneficial owner as of the Effective Time will remain outstanding as Partnership Interests of the Surviving Entity and will not be converted into the right to receive the Merger Consideration or any other form of consideration.

ARTICLE 6 MISCELLANEOUS

Section 6.1 Termination. This Agreement shall remain in effect until the earliest to occur of (a) the Effective Time, (b) the termination of the Merger Agreement in accordance with its terms (including after any extension thereof), (c) the GP Board (after consulting the GP Conflicts Committee) making a Partnership Adverse Recommendation Change, (d) the written agreement of EEP, EECI and MEP to terminate this Agreement or (e) the date of any modification, waiver or amendment to the Merger Agreement without the prior written consent of EEP (such earliest date being referred to herein as the “Termination Date”). After the occurrence of such applicable event, this Agreement shall terminate and be of no further force or effect. Nothing in this Section 6.1 and no termination of this Agreement shall relieve or otherwise limit any party of liability for any breach of this Agreement occurring prior to such termination.

Section 6.2 No Ownership Interest. Nothing contained in this Agreement shall be deemed to vest in MEP or EECI any direct or indirect ownership or incidence of ownership of or with respect to any Covered Units. All rights, ownership and economic benefit relating to the Covered Units shall remain vested in and belong to EEP, and MEP and EECI shall have no authority to direct EEP in the voting or disposition of any of the Covered Units, except as otherwise provided herein.

Section 6.3 Publicity. EEP hereby permits MEP to include and disclose in the Partnership Information Statement and in such other schedules, certificates, applications, agreements or documents as such entities reasonably determine to be necessary or appropriate in connection with the consummation of the Merger and the transactions contemplated by the Merger Agreement EEP’s identity and ownership of the Covered Units and the nature of EEP’s commitments, arrangements and understandings pursuant to this Agreement.

Section 6.4 Notices. All notices and other communications hereunder shall be in writing and shall be deemed given when delivered personally or by telecopy (upon telephonic confirmation of receipt) or on the first Business Day following the date of dispatch if delivered by a recognized next day courier service. All notices hereunder shall be delivered as set forth below or pursuant to such other instructions as may be designated in writing by the party to receive such notice:

If to EEP, to:

Enbridge Energy Partners, L.P.

 

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1100 Louisiana St., Suite 3300

Houston, Texas 77002

Attention: Mark Boyce

With copies to:

Vinson & Elkins

First City Tower, 1001 Fannin St., Suite 2500

Houston, Texas 77002

Attention: Michael Telle

If to MEP, to:

Midcoast Energy Partners, L.P.

1100 Louisiana St., Suite 3300

Houston, Texas 77002

Attention: Chris Kaitson

With copies to:

Bracewell LLP

711 Louisiana Street, Suite 2300

Houston, Texas 77002

Attention: Will Anderson

If to EECI, to:

Enbridge Energy Company, Inc.

1100 Louisiana St., Suite 3300

Houston, Texas 77002

Attention: Mark Boyce

With copies to:

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Attention: Brett E. Braden

Section 6.5 Interpretation. The words “hereof,” “herein” and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement, and Section references are to this Agreement unless otherwise specified. Whenever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation.” The meanings given to terms defined herein shall be equally applicable to both the singular and plural forms of such terms. The headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. This Agreement is the product of negotiation by the parties having the assistance of counsel and other advisers. It is the intention of the parties that this Agreement not be construed more strictly with regard to one party than with regard to the others.

Section 6.6 Counterparts. This Agreement may be executed by facsimile and in counterparts, all of which shall be considered one and the same agreement and shall become effective when counterparts have been signed by each of the parties and delivered to the other parties, it being understood that all parties need not sign the same counterpart.

 

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Section 6.7 Expenses. Except as otherwise provided herein, all costs and expenses in connection with this Agreement shall be paid by the party incurring such cost or expense, whether or not the transactions contemplated hereby are consummated.

Section 6.8 Entire Agreement. This Agreement and, solely to the extent of the defined terms referenced herein, the Merger Agreement embody the complete agreement and understanding among the parties hereto with respect to the subject matter hereof and supersede and preempt any prior understandings, agreements or representations by or among the parties, written and oral, that may have related to the subject matter hereof in any way.

Section 6.9 Governing Law; Consent to Jurisdiction; Waiver of Jury Trial.

(a) This Agreement shall be governed by, and interpreted in accordance with, the laws of the State of Delaware (except to the extent that mandatory provisions of federal law govern), without regard to the conflict of law principles thereof.

(b) Each of the parties hereto irrevocably agrees that any legal action or proceeding with respect to this Agreement and the rights and obligations arising hereunder shall be brought and determined exclusively in the Delaware Court of Chancery and any state appellate court therefrom within the State of Delaware (or, if the Delaware Court of Chancery declines to accept jurisdiction over a particular matter, any state or federal court within the State of Delaware). Each of the parties hereto consents to service of process being made upon it through the notice procedures set forth in Section 6.4, irrevocably submits with regard to any such action or proceeding for itself and in respect of its property, generally and unconditionally, to the personal jurisdiction of the aforesaid courts and agrees that it will not bring any action relating to this Agreement or any of the transactions contemplated hereby in any court other than the aforesaid courts. Each of the parties hereto irrevocably waives, and agrees not to assert as a defense, counterclaim or otherwise, in any action or proceeding with respect to this Agreement, (i) any claim that it is not personally subject to the jurisdiction of the above named courts for any reason other than the failure to serve in accordance with this Section 6.9, (ii) any claim that it or its property is exempt or immune from the jurisdiction of any such court or from any legal process commenced in such courts (whether through service of notice, attachment prior to judgment, attachment in aid of execution of judgment, execution of judgment or otherwise) and (iii) to the fullest extent permitted by applicable law, any claim that (A) the suit, action or proceeding in such court is brought in an inconvenient forum, (B) the venue of such suit, action or proceeding is improper or (C) this Agreement, or the subject matter hereof, may not be enforced in or by such courts. Each party hereto expressly acknowledges that the foregoing waiver is intended to be irrevocable under the laws of the State of Delaware and of the United States of America; provided, however, that each such party’s consent to jurisdiction and service contained in this Section 6.9(b) is solely for the purposes referred to in this Section 6.9(b) and shall not be deemed to be a general submission to such courts or in the State of Delaware other than for such purposes.

(c) EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATED TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY.

Section 6.10 Amendment; Waiver. This Agreement may not be amended except by an instrument in writing signed by MEP, EECI and EEP. Each party may waive any right of such party hereunder by an instrument in writing signed by such party and delivered to the other parties hereto.

Section 6.11 Remedies.

(a) Each party hereto acknowledges that monetary damages would not be an adequate remedy in the event that any covenant or agreement in this Agreement is not performed in accordance with its terms, and it is therefore agreed that, in addition to and without limiting any other remedy or right it may have, the

 

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non-breaching party will have the right to an injunction, temporary restraining order or other equitable relief in any court of competent jurisdiction enjoining any such breach and enforcing specifically the terms and provisions hereof. Each party hereto agrees not to oppose the granting of such relief in the event a court determines that such a breach has occurred, and to waive any requirement for the securing or posting of any bond in connection with such remedy.

(b) All rights, powers and remedies provided under this Agreement or otherwise available in respect hereof at law or in equity shall be cumulative and not alternative, and the exercise or beginning of the exercise of any thereof by any party shall not preclude the simultaneous or later exercise of any other such right, power or remedy by such party.

Section 6.12 Severability. Any term or provision of this Agreement which is determined by a court of competent jurisdiction to be invalid or unenforceable in any jurisdiction shall, as to that jurisdiction, be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this Agreement or affecting the validity or enforceability of any of the terms or provisions of this Agreement in any other jurisdiction, and if any provision of this Agreement is determined to be so broad as to be unenforceable, the provision shall be interpreted to be only so broad as is enforceable, in all cases so long as neither the economic nor legal substance of the transactions contemplated hereby is affected in any manner adverse to any party or its equityholders. Upon any such determination, the parties shall negotiate in good faith in an effort to agree upon a suitable and equitable substitute provision to effect the original intent of the parties as closely as possible and to the end that the transactions contemplated hereby shall be fulfilled to the maximum extent possible.

Section 6.13 Action by MEP. No waiver, consent or other action by or on behalf of MEP pursuant to or as contemplated by this Agreement shall have any effect unless such waiver, consent or other action is expressly approved by the GP Board and the GP Conflicts Committee.

Section 6.14 Successors and Assigns; Third Party Beneficiaries. Except as permitted by Section 5.1, neither this Agreement nor any of the rights or obligations of any party under this Agreement shall be assigned, in whole or in part (by operation of law or otherwise), by any party without the prior written consent of the other parties hereto. Subject to the foregoing, this Agreement shall bind and inure to the benefit of and be enforceable by the parties hereto and their respective successors and permitted assigns. Nothing in this Agreement, express or implied, is intended to confer on any Person other than the parties hereto or the parties’ respective successors and permitted assigns any rights, remedies, obligations or liabilities under or by reason of this Agreement.

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed (where applicable, by their respective officers or other authorized Person thereunto duly authorized) as of the date first written above.

 

MIDCOAST ENERGY PARTNERS, L.P.

By:

 

Midcoast Holdings, L.L.C,

its general partner

By:  

/s/ C. GREGORY HARPER

  Name: C. Gregory Harper
  Title: President

 

ENBRIDGE ENERGY PARTNERS, L.P.

By:

  Enbridge Energy Management, L.L.C., as delegate of Enbridge Energy Company, Inc., its general partner

By:

 

/s/ VALORIE J. WANNER

  Name: Valorie Wanner
  Title: Corporate Secretary

 

ENBRIDGE ENERGY COMPANY, INC.

By:  

/s/ NOOR S. KAISSI

  Name: Noor S. Kaissi
  Title: Controller

Signature Page to Support Agreement

 

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ANNEX C

January 26, 2017

Conflicts Committee of the Board of Directors of Midcoast Holdings, L.L.C.

Midcoast Holdings, L.L.C.

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

Members of the Conflicts Committee:

We understand that Enbridge Energy Company, Inc., a Delaware corporation (“Parent”), Enbridge Holdings (Leather) L.L.C., a Delaware limited liability company and wholly-owned subsidiary of Parent (“Merger Sub”), Midcoast Energy Partners, L.P., a Delaware limited partnership (the “Partnership”), and Midcoast Holdings, L.L.C., a Delaware limited liability company and the general partner of the Partnership (“Partnership GP”), propose to enter into an Agreement and Plan of Merger, dated as of the date hereof (the “Merger Agreement”), pursuant to which Merger Sub will be merged with and into the Partnership (the “Merger”), with the Partnership surviving the Merger as a Delaware limited partnership. In the Merger, each of the Partnership’s outstanding Class A Common Units (each, a “Common Unit”), other than the Common Units owned by Parent and its Affiliates and Enbridge Energy Partners, L.P., a Delaware limited partnership (“EEP”), will be converted into the right to receive $8.00 per Common Unit in cash (the “Consideration”). As a result of the Merger, Partnership GP will remain the general partner of the Partnership and Parent and EEP will hold all of the limited partner interests of the Partnership. The terms and conditions of the Merger are more fully set forth in the Merger Agreement, and capitalized terms used herein and not defined shall have the meanings ascribed thereto in the Merger Agreement.

The Conflicts Committee of the Board of Directors of Partnership GP (the “Conflicts Committee”) has asked us whether, in our opinion, as of the date hereof, the Consideration is fair, from a financial point of view, to the holders of Common Units (other than Parent, EEP, Partnership GP and their respective Affiliates).

In connection with rendering our opinion, we have, among other things:

 

  (i) reviewed certain publicly available historical business and financial information relating to the Partnership that we deemed to be relevant, including information set forth in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015, Quarterly Reports on Form 10-Q for the quarters ended March 31, 2016, June 30, 2016 and September 30, 2016 and Current Reports on Form 8-K filed since January 1, 2016, in each case as filed with or furnished to the U.S. Securities and Exchange Commission by the Partnership;

 

  (ii) reviewed certain non-public historical and projected financial and operating data relating to the Partnership prepared and furnished to us by management of the Partnership;

 

  (iii) discussed the past and current operations, financial projections and current financial condition of the Partnership with management of the Partnership (including management’s views on the risks and uncertainties of achieving such projections);

 

  (iv) reviewed certain publicly available research analyst estimates for the Partnership’s future financial performance on a standalone basis;

 

  (v) reviewed the reported prices and the historical trading activity of the Common Units;

 

  (vi) compared the financial performance of the Partnership and its stock market trading multiples with publicly available financial terms of certain other publicly traded companies that we deemed relevant;

 

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Conflicts Committee of the

Board of Directors of Midcoast Holdings, L.L.C.

January 26, 2017

Page- 2

 

 

  (vii) compared the financial performance of the Partnership and the valuation multiples implied by the Merger with those of certain other transactions that we deemed relevant;

 

  (viii) performed a discounted cash flow analysis based on forecasts and other data provided by management of the Partnership;

 

  (ix) performed a discounted distributions analysis based on forecasts and other data provided by management of the Partnership;

 

  (x) reviewed the premiums paid in certain historical transactions that we deemed relevant and compared such premiums to those implied by the Merger;

 

  (xi) reviewed information regarding the process conducted by EEP with respect to soliciting third parties to acquire EEP’s general partner and limited partner interests in the Partnership and EEP’s limited partner interest in Midcoast Operating, L.P. (“MOLP”) or, alternatively, all of the general partner and limited partner interests in the Partnership and MOLP;

 

  (xii) reviewed a draft of the Merger Agreement dated January 25, 2017;

 

  (xiii) reviewed a draft of the EEP Support Agreement dated January 25, 2017; and

 

  (xiv) performed such other analyses and examinations, reviewed such other information and considered such other factors that we deemed appropriate for the purposes of providing the opinion contained herein.

For purposes of our analysis and opinion, we have assumed and relied upon, without undertaking any independent verification of, the accuracy and completeness of all of the information publicly available, and all of the information supplied or otherwise made available to, discussed with, or reviewed by us, and we assume no liability therefor. With respect to the projected financial and operating data relating to the Partnership, we have assumed that such data have been reasonably prepared on bases reflecting the best currently available estimates and good faith judgments of the management of the Partnership as to the future competitive, operating and regulatory environments and related financial performance of the Partnership under the assumptions stated therein. Among other things, we took into consideration the financial impact on the holders of Common Units of the projected substantial reduction in quarterly distributions payable on Common Units reflected in the projected financial and operating data relating to the Partnership prepared and furnished to us by management of the Partnership. We express no view as to any projected financial or operating data relating to the Partnership or any judgments, estimates or assumptions on which such data are based. We have relied, at your direction, without independent verification, upon the assessments of the management of the Partnership as to the future financial and operating performance of the Partnership.

For purposes of rendering our opinion, we have assumed that the representations and warranties of each party contained in the Merger Agreement and the EEP Support Agreement (in the draft forms reviewed by us) are true and correct in all respects material to our analysis, that each party will perform all of the covenants and agreements required to be performed by it under the Merger Agreement and the EEP Support Agreement and that all conditions to the consummation of the Merger will be satisfied without material waiver or modification thereof. We have further assumed that all governmental, regulatory or other consents, approvals or releases necessary for the consummation of the Merger will be obtained without any material delay, limitation, restriction or condition that would have an adverse effect on the Partnership or the consummation of the Merger or materially reduce the benefits of the Merger to the holders of Common Units. We have assumed that the final versions of all documents reviewed by us in draft form will conform in all material respects to the drafts reviewed by us.

 

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Conflicts Committee of the

Board of Directors of Midcoast Holdings, L.L.C.

January 26, 2017

Page- 3

 

We have not made, nor assumed any responsibility for making, any independent valuation or appraisal of the assets or liabilities of the Partnership or any of its subsidiaries, nor have we been furnished with any such appraisals, nor have we evaluated the solvency or fair value of the Partnership or any of its subsidiaries under any state or federal laws relating to bankruptcy, insolvency or similar matters. Our opinion is necessarily based upon information made available to us as of the date hereof and financial, economic, market and other conditions as they exist and as can be evaluated as of the date hereof. It is understood that subsequent developments may affect this opinion and that we do not have any obligation to update, revise or reaffirm this opinion.

We have not been asked to pass upon, and express no opinion with respect to, any matter other than the fairness of the Consideration, from a financial point of view, as of the date hereof, to the holders of Common Units (other than Parent, EEP, Partnership GP and their respective Affiliates). We do not express any view on, and our opinion does not address, the fairness, financial or otherwise, of the Merger to, or any consideration received in connection therewith by, the holders of any other securities, creditors or other constituencies of the Partnership, nor the fairness of the amount or nature of any compensation to be paid or payable to any of the officers, directors or employees of Partnership GP, the Partnership or any other parties to the Merger Agreement or affiliates thereof or any class of such persons, whether relative to the Consideration, the Merger or otherwise. We have assumed that any modification to the structure of the Merger will not vary in any respect material to our analysis. Our opinion does not address the relative merits of the Merger as compared to other business or financial strategies or opportunities that might be available to the Partnership, nor does it address the underlying business decision of the Partnership to engage in the Merger. In arriving at our opinion, we were not authorized to solicit, and did not solicit, interest from any third party with respect to the acquisition of any or all of the Common Units or any business combination or other extraordinary transaction involving the Partnership. Neither this letter nor our opinion constitutes a recommendation to the Conflicts Committee or to any other persons in respect of the Merger, including as to how any holder of units of the Partnership should vote or act in respect of the Merger. We express no opinion herein as to the price at which the Common Units will trade at any time. We are not legal, regulatory, accounting or tax experts and have assumed the accuracy and completeness of assessments by the Partnership and the Partnership’s advisors with respect to legal, regulatory, accounting and tax matters.

We received an initial fee for our services and will receive an additional fee upon the rendering of this opinion. The Partnership has also agreed to reimburse our expenses and to indemnify us against certain liabilities arising out of our engagement. During the two-year period prior to the date hereof, other than respect to its opinion and work performed for the Conflicts Committee in connection with the Conflicts Committee’s consideration of a proposed subscription agreement with respect to the issuance by the Partnership to EEP of up to $250 million of a new class of limited partnership interests in the Partnership convertible into Common Units, no material relationship existed between Evercore Group L.L.C. or any of its affiliates, on the one hand, and the Partnership, EEP, Partnership GP, Parent or any of their respective affiliates, on the other hand, pursuant to which compensation was received or is intended to be received by Evercore Group L.L.C. or its affiliates as a result of such relationship. We and our affiliates may provide financial or other services to the Partnership, EEP, Partnership GP or Parent or any of their respective affiliates in the future and in connection with any such services we may receive compensation.

In the ordinary course of business, Evercore Group L.L.C. and its affiliates may actively trade the securities, or related derivative securities, or financial instruments of the Partnership, EEP, Parent and their respective affiliates, for its own account and for the accounts of its customers and, accordingly, may at any time hold a long or short position in such securities or instruments.

 

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Conflicts Committee of the

Board of Directors of Midcoast Holdings, L.L.C.

January 26, 2017

Page- 4

 

This letter and the opinion expressed herein is addressed to, and is for the information and benefit of, the Conflicts Committee in connection with its evaluation of the Merger. The issuance of this opinion has been approved by an Opinion Committee of Evercore Group L.L.C.

This letter, and the opinion expressed herein, may not be disclosed, quoted, used, referred to or communicated (in whole or in part) to, or relied upon by, any third party, nor shall any public reference to us be made, for any purpose whatsoever except with our prior written approval or in accordance with the terms of the engagement letter, dated December 22, 2016, among the Partnership, the Conflicts Committee and Evercore Group L.L.C.

Based upon and subject to the foregoing, it is our opinion that, as of the date hereof, the Consideration is fair, from a financial point of view, to the holders of Common Units (other than Parent, EEP, Partnership GP and their respective Affiliates).

Very truly yours,

EVERCORE GROUP L.L.C.

By:

 

  /s/ Raymond B. Strong III
 

Raymond B. Strong III

Senior Managing Director

 

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ANNEX D

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

or

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to                 

Commission file number 1-36175

 

 

MIDCOAST ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   61-1714064

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

1100 Louisiana Street, Suite 3300, Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code (713) 821-2000

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Class A common units   New York Stock Exchange

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☐    No  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer   ☐  (Do not check if a smaller reporting company)    Smaller reporting company  

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The aggregate market value of the registrant’s Class A common units held by non-affiliates computed by reference to the price at which the common equity was last sold on June 30, 2016, was $180,770,962.

As of February 14, 2017, the registrant has 22,610,056 Class A common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 

 

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TABLE OF CONTENTS

 

          Page  
  

PART I

  
Item 1.   

Business

     D-7  
Item 1A.   

Risk Factors

     D-23  
Item 2.   

Properties

     D-55  
Item 3.   

Legal Proceedings

     D-56  
Item 4.   

Mine Safety Disclosures

     D-56  
  

PART II

  
Item 5.   

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

     D-57  
Item 6.   

Selected Financial Data

     D-58  
Item 7.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     D-59  
Item 7A.   

Quantitative and Qualitative Disclosures About Market Risk

     D-83  
Item 8.   

Financial Statements and Supplementary Data

     D-88  
Item 9.   

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     D-150  
Item 9A.   

Controls and Procedures

     D-150  
Item 9B.   

Other Information

     D-151  
  

PART III

  
Item 10.   

Directors, Executive Officers and Corporate Governance

     D-152  
Item 11.   

Executive Compensation

     D-158  
Item 12.   

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

     D-181  
Item 13.   

Certain Relationships and Related Transactions, and Director Independence

     D-183  
Item 14.   

Principal Accountant Fees and Services

     D-184  
  

PART IV

  
Item 15.   

Exhibits and Financial Statement Schedules

     D-185  
Signatures      D-186  

In this report unless the context otherwise requires, references to “Midcoast Energy Partners,” “the Partnership,” “MEP,” “we,” “our,” “us,” or like terms refer to Midcoast Energy Partners, L.P. and its subsidiaries. We refer to our general partner, Midcoast Holdings, L.L.C., as our “General Partner” and to Enbridge Energy Partners, L.P. and its subsidiaries, other than us, as “Enbridge Energy Partners,” or “EEP.” References to “Enbridge” refer collectively to Enbridge Inc. and its subsidiaries other than us, our subsidiaries, our General Partner, EEP, its subsidiaries and its general partner. References to “Enbridge Management” refer to Enbridge Energy Management, L.L.C., the delegate of EEP’s general partner that manages EEP’s business and affairs. References to “Midcoast Operating” refer to Midcoast Operating, L.P. and its subsidiaries. As of December 31, 2016, we owned a 51.6% controlling interest, in Midcoast Operating, and EEP owned a 48.4% noncontrolling interest, or NCI, in Midcoast Operating. Unless otherwise specifically noted, financial results and operating data are shown on a 100% basis and are not adjusted to reflect EEP’s 48.4% NCI in Midcoast Operating as of December 31, 2016.

This Annual Report on Form 10-K includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “consider,” “continue,” “could,” “estimate,” “evaluate,” “expect,” “explore,” “forecast,” “intend,” “may,” “opportunity,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and

 

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assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Annual Report on Form 10-K speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for the supply of, forecast data for, and price trends related to natural gas, natural gas liquids, or NGLs, and crude oil, and the response by natural gas and crude oil producers to changes in any of these factors; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline and gathering systems, as well as other processing and treating plants; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to which we sell products; (5) hazards and operating risks that may not be covered fully by insurance; (6) changes in or challenges to our rates; (7) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; (8) cost overruns and delays on construction projects resulting from numerous factors; (9) our ability to comply with covenants in our debt agreements; and (10) the possibility that the Merger with MergerCo may not be consummated in a timely manner or at all and the diversion of management’s attention in connection with the proposed Merger.

For additional factors that may affect results, see “Item-1A. Risk Factors” included elsewhere in this Annual Report on Form 10-K, our subsequently filed Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K which are available to the public over the Internet at the U.S. Securities and Exchange Commission’s, or the SEC’s, website (www.sec.gov) and at our website (www.midcoastpartners.com).

 

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Glossary

The following abbreviations, acronyms and terms used in this Form 10-K are defined below:

 

Anadarko system    Natural gas gathering and processing assets located in western Oklahoma and the Texas panhandle which serve the Anadarko basin, inclusive of the Elk City system
AOCI    Accumulated other comprehensive income
APSA    Accountable Pipeline Safety and Partnership Act of 1996
Bbl    Barrel of liquids (approximately 42 United States gallons)
Bpd    Barrels per day
CAA    Clean Air Act
CERCLA    Comprehensive Environmental Response, Compensation, and Liability Act
CFTC    Commodity Futures Trading Commission
CWA    Clean Water Act
Dodd-Frank Act    Dodd-Frank Wall Street Reform and Consumer Protection Act
DOT    United States Department of Transportation
East Texas system    Natural gas gathering, treating and processing assets in East Texas that serve the Bossier trend and Haynesville shale areas, also includes a system formerly known as the Northeast Texas system
EBITDA    Earnings before Interest, Taxes, Depreciation and Amortization
EECI    Enbridge Energy Company, Inc.
EEP    Enbridge Energy Partners, L.P. and its subsidiaries other than Midcoast Energy Partners, L.P. and its subsidiaries
Enbridge    Enbridge Inc., of Calgary, Alberta, Canada, the ultimate parent of the General Partner
Enbridge Management    Enbridge Energy Management, L.L.C.
EP Act    Energy Policy Act of 1992
EPA    Environmental Protection Agency
Exchange Act    Securities Exchange Act of 1934, as amended
FERC    Federal Energy Regulatory Commission
General Partner    Midcoast Holdings, L.L.C., the general partner of the Partnership
GPP    Gas Pipelines and Processing
HCA    High consequence area
HLPSA    Hazardous Liquid Pipeline Safety Act of 1979
ICA    Interstate Commerce Act
IRA    Individual retirement accounts
ISDA®    International Swaps and Derivatives Association, Inc.

 

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LIBOR    London Interbank Offered Rate — British Bankers’ Association’s average settlement rate for deposits in United States dollars
MEP    Midcoast Energy Partners, L.P. and its consolidated subsidiaries
Merger    The proposed merger of MergerCo with and into MEP pursuant to the terms and conditions of the Merger Agreement whereby (i) EECI will acquire all of MEP’s outstanding common units not already owned by EECI, EEP or their affiliates, (ii) MergerCo will merge with and into MEP, (iii) the separate limited liability company existence of MergerCo will cease, (iv) and MEP will continue its existence as a limited partnership under Delaware law as the surviving entity in the Merger
Merger Agreement    Agreement and Plan of Merger dated January 26, 2017, with EECI, MergerCo, MEP and Midcoast Holdings, L.L.C., the general partner of MEP
MergerCo    Enbridge Holdings (Leather) L.L.C., an indirect wholly-owned subsidiary of EECI
MIC    Enbridge Management Information Circular
MLP    Master Limited Partnership
MMBbls    Million barrels of liquids
MMBtu/d    Million British Thermal units per day
MMcf/d    Million cubic feet per day
NAAQs    National Ambient Air Quality Standards
NGA    Natural Gas Act of 1938
NGLs    Natural gas liquids
NGPA    Natural Gas Policy Act of 1978
NGPSA    Natural Gas Pipeline Safety Act of 1968
North Texas system    Natural gas gathering and processing assets located in the Fort Worth basin serving the Barnett Shale area
NPNS    Normal purchases and normal sales
NSPS    New Source Performance Standards
NYSE    New York Stock Exchange
OCC    Oklahoma Corporation Commission
Offering    MEP initial public offering
OLP    Enbridge Energy, Limited Partnership
OPA    Oil Pollution Act
Partnership Agreement    First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P., also referred to as our partnership agreement
Partnership    Midcoast Energy Partners, L.P. and its consolidated subsidiaries
PHMSA    Pipeline and Hazardous Materials Safety Administration
PIPES Act of 2006    Pipeline Inspection, Protection, Enforcement and Safety Act of 2006
PIPES Act of 2016    Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016

 

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Ppb    Parts per billion
PSA    Pipeline Safety Act of 1992
PSIA    Pipeline Safety Improvement Act of 2002
SEC    United States Securities and Exchange Commission
Texas Express NGL system    NGL gathering system and an NGL interstate mainline transportation pipeline that originates in Skellytown, Texas, and extends to NGL fractionation and storage facilities located in Mont Belvieu, Texas
TRI    Toxic Release Inventory
TRRC    Texas Railroad Commission
TSX    Toronto Stock Exchange
U.S. GAAP    United States Generally Accepted Accounting Principles
WOTUS    Waters of the United States

 

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PART I

Item 1. Business

OVERVIEW

Midcoast Energy Partners, L.P. is a publicly-traded Delaware limited partnership formed in 2013 by Enbridge Energy Partners, L.P., or EEP, to serve as EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. Midcoast Energy Partners, L.P., together with its consolidated subsidiaries, are referred to in this report as “we,” “us,” “our,” “MEP,” and the “Partnership.” As a pure-play U.S. natural gas and NGL midstream business, we are able to pursue a focused and flexible strategy and have the opportunity to grow through organic growth opportunities and acquisitions. Our Class A common units are traded on the New York Stock Exchange, or NYSE, under the symbol “MEP.”

We own, directly or indirectly, a 51.6% limited partner interest in Midcoast Operating, L.P., or Midcoast Operating, a Texas limited partnership that owns a network of natural gas and NGL gathering and transportation systems, natural gas processing and treating facilities and NGL fractionation facilities primarily located in Texas and Oklahoma. We also own 100% of Midcoast Operating’s general partner. Midcoast Operating also owns and operates natural gas, condensate and NGL logistics and marketing assets that primarily support its gathering, processing and transportation business. Through our ownership of Midcoast Operating’s general partner, we control, manage and operate these systems. EEP owns a 48.4% noncontrolling interest in Midcoast Operating. Unless otherwise specifically noted, financial results and operating data are shown on a 100% basis.

Merger Agreement

We and our general partner entered into an Agreement and Plan of Merger dated as of January 26, 2017 with EECI and Enbridge Holdings (Leather) L.L.C. pursuant to which EECI will acquire all of MEP’s outstanding common units not already held by EECI, EEP or their affiliates (the “Public Units”). The holders of the Public Units will receive $8.00 in cash for each Public Unit. The Merger is expected to close in the second quarter of 2017, pending the satisfaction of certain customary conditions and the approval of the Merger by the affirmative vote of holders of a majority of the outstanding MEP common units (including the MEP common units held by EEP and its affiliates). Upon completion of the transaction, MEP will continue to exist as a limited partnership, but will no longer have publicly listed or traded units, nor will it be a reporting company under the SEC’s rules and regulations. For additional information on the Merger, refer to Part II, Item 8. Financial Statements and Supplementary Data, Note 1, Organization and Nature of Operations.

The following chart shows our organization and ownership structure as of December 31, 2016. The ownership percentages set forth below illustrate the relationships among us, Midcoast Operating, our General Partner, EEP, Enbridge and its affiliates; such ownership interests may be held directly or indirectly:

 

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LOGO

Our business primarily consists of gathering unprocessed and untreated natural gas from wellhead locations and other receipt points on our systems, processing the natural gas to remove NGLs and impurities at our processing and treating facilities and transporting the processed natural gas and NGLs to intrastate and interstate pipelines for transportation to various customers and market outlets. In addition we also provide marketing services of natural gas and NGLs to wholesale customers.

 

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We seek to provide our customers with quality field-level service and responsiveness using our strong platform of natural gas and NGL infrastructure. We are able to provide our customers with integrated wellhead-to-market service from our systems to major energy market hubs in the Gulf Coast and Mid-Continent regions of the United States. From these market hubs, natural gas and NGLs are either consumed in local markets or transported to consumers in the midwest, northeast and southeast United States.

BUSINESS STRATEGY

We have historically sought to increase the amount of cash distributions we make to our unitholders over time while maintaining our focus on safety and stability in our business. We pursued this objective through, among other things, the following business strategies:

 

  1. Delivering our services safely and reliably

We are committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is key to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We strive for operational excellence by utilizing robust programs to integrate environmental integrity, health and occupational safety and risk management principles throughout our business. We employ comprehensive integrity management, inspection, monitoring and audit initiatives in support of this strategy.

 

  2. Enhancing the profitability of our existing assets

To address the continuing producer focus on the liquids portion of the midstream natural gas value chain, we expect to further optimize our natural gas processing capacity, NGL takeaway capacity options, and our third-party fractionation alternatives, which we believe will, over the long-term, increase the attractiveness and profitability of our natural gas and NGL systems, attract new customers and increase our business with existing customers. We seek to capitalize on opportunities to attract new customers, increase volumes of natural gas and NGLs that we gather, process or treat, transport and otherwise enhance utilization and operating efficiencies, including increasing customer access to preferred natural gas and NGL markets. We are committed to increase our percentage of fee-based contracts to reduce commodity exposure and further strengthen our profitability. We believe our approach provides our customers with greater value for their commodities and increases the utilization of our natural gas and NGL systems.

 

  3. Maintaining a conservative and flexible capital structure

We intend to finance long-term growth projects and acquisitions primarily through our credit facility and in the longer term through term debt and equity. Over the longer term, we are seeking a balanced combination of debt and equity that we believe will promote the long-term stability of our business.

 

  4. Pursuing economically attractive organic growth opportunities

We seek out attractive organic expansion and asset enhancement opportunities that leverage our existing asset footprint, strategic relationships with our customers and our expertise in constructing, developing and optimizing midstream infrastructure assets. The organic development projects we pursue are designed to extend our geographic reach, diversify our customer base, expand our gathering systems and our processing and treating capacity, enhance end-market access and maximize throughput volumes. For more information relating to growth opportunities refer to Business Segments.

 

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  5. Pursuing accretive acquisitions from third parties

We intend to pursue accretive acquisitions from third parties that complement or diversify our existing operations, if and when market conditions improve.

While the Merger will result in our no longer having publicly traded units, we will continue to work with EEP to explore and evaluate strategic alternatives in addition to, or as alternatives to, our historical business strategies. EEP has also indicated that it is reviewing strategic alternatives with respect to its investment in us and Midcoast Operating.

BUSINESS SEGMENTS

We conduct our business through two distinct reporting segments: Gathering, Processing and Transportation and Logistics and Marketing.

These segments have unique business activities that require different operating strategies. For information relating to revenues from third-party customers, operating income and total assets for each segment, refer to Part II, Item 8. Financial Statements and Supplementary Data, Note 5. Segment Information.

Gathering, Processing and Transportation

Our gathering, processing and transportation business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. We gather natural gas from the wellhead and central receipt points on our systems, deliver it to our facilities for processing and treating and deliver the residue gas to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies. We deliver the NGLs produced at our processing and fractionation facilities to intrastate and interstate pipelines for transportation to the NGL market hubs in Mont Belvieu, Texas and Conway, Kansas. In addition, we deliver NGLs from certain of our facilities to the Texas Express NGL system for transportation on the Texas Express NGL mainline to Mont Belvieu, Texas.

The following table provides selected information regarding our natural gas and NGL systems in our gathering, processing and transportation business at December 31, 2016:

 

    Natural gas
gathering and
transportation
pipelines
(length in
miles)
    NGL pipelines
(length in
miles) (4)
    Number of
active natural
gas processing
plants
    Number of
standby
natural gas
processing
plants
    Number of
active natural
gas treating
plants
    Number of
standby
natural gas
treating plants
 

Anadarko system

    3,100       89       5       7       —         1  

East Texas system (1)

    4,000       177       6       1       4       5  

North Texas system

    3,700       16       4       2       —         —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

    10,800       282       15       10       4       6  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Texas Express NGL system (2)

    —         709 (3)      —         —         —         —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)  In addition, a fractionation facility is located in the East Texas basin.
(2)  We have a 35% interest in the Texas Express NGL system, which commenced startup operations during the fourth quarter of 2013.
(3)  Consists of approximately 593-mile NGL intrastate transportation mainline and a related NGL gathering system that consists of approximately 116 miles of gathering lines.

 

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Anadarko System

Our Anadarko system includes production from the Granite Wash tight sand formation. Productive horizons in the Granite Wash play include the Hogshooter, Checkerboard, Cleveland, Skinner, Red Fork, Atoka and Morrow formations. Recent decreases in NGL and condensate prices have resulted in decreased activity in the region. The Anadarko basin wells generally have long lives with predictable flow rates. Producers generally pursue wells with higher condensate and oil production relative to historical activity that was focused on natural gas and NGL prospects.

With recent commodity prices in decline resulting in reduced production, we have idled approximately seven of our less efficient processing plants and consolidated volumes to our more efficient plants. These plants are available for restart when production increases.

Our Anadarko system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the Mid-Continent and Gulf Coast regions of the United States. All of our owned residue gas and condensate is sold to our logistics and marketing business. The majority of our owned NGLs are also sold to our logistics and marketing business with the remainder being sold directly to a third-party. The NGLs produced at our Anadarko system processing plants are transported by pipeline to third-party fractionation facilities and NGL market hubs in Conway, Kansas and Mont Belvieu, Texas.

East Texas System

Our East Texas system gathers production from: the Cotton Valley, James Lime and lean Bossier Shale plays, which are located on the western side of our East Texas system; the Haynesville/Bossier Shale plays, which run from western Louisiana into East Texas and are among the largest natural gas resources in the United States; and the Cotton Valley Sand formation, which also runs from western Louisiana into East Texas and has a high content of NGLs and condensate on the eastern side of our East Texas system. The East Texas basin also includes multiple other natural gas and oil formations that are frequently explored, including among others, the Woodbine, Travis Peak, Rodessa, and Pettite. The East Texas wells generally have long lives with predictable flow rates.

In May 2015, we placed into service a cryogenic natural gas processing plant near Beckville in Panola County, Texas, which we refer to as the Beckville Processing Plant. This plant serves existing and prospective customers pursuing production in the Cotton Valley formation, which is comprised of approximately ten counties in East Texas. Our Beckville processing plant is capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs to accommodate the additional liquids-rich natural gas within this geographical area in which our East Texas system operates. Related NGL takeaway infrastructure connecting the Beckville plant to third-party NGL transportation systems was also constructed. In 2016, our processing plants in East Texas were near or at full capacity.

Our East Texas system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the United States Gulf Coast, as well as to several wholesale customers. The majority of our owned residue gas is sold to our logistics and marketing business, while the remainder of our owned residue gas is sold directly to third-party wholesale customers or utilities. Our owned condensate is also sold to our logistics and marketing business. A portion of the NGLs produced at one of our East Texas system processing plants is fractionated by us and sold directly to a third-party chemical company. The remainder of the NGLs recovered at our plants are sold to our logistics and marketing business and transported by pipeline to Mont Belvieu, Texas for fractionation.

 

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North Texas System

A substantial portion of natural gas on our North Texas system is produced in the Barnett Shale play within the Fort Worth basin. The North Texas wells are located in the Fort Worth basin and generally have long lives with predictable flow rates. As producers have shifted to more economic advantaged basins, we have seen our natural gas volumes decline in the basin.

Our North Texas system has numerous market outlets for the natural gas that we gather and process and NGLs that we recover on our system. We have connections to major intrastate transportation pipelines that connect our facilities to market centers in the Dallas-Fort Worth area. All of our owned condensate and NGLs produced at our North Texas system processing plants are sold to our logistics and marketing business. The majority of our owned residue gas is also sold to our logistics and marketing business.

Texas Express NGL System

We own a 35% interest in two joint ventures that together comprise the Texas Express NGL system. The Texas Express NGL system consists of an NGL gathering system and an NGL intrastate mainline transportation pipeline that originates in Skellytown, Texas, and extends to NGL fractionation and storage facilities located in Mont Belvieu, Texas. Volumes from the Rockies, Permian basin and Mid-Continent regions are delivered to the Texas Express NGL system utilizing the Mid-America Pipeline between the Conway hub and the Hobbs NGL fractionation facility in West Texas, both of which are owned by a third party. In addition, volumes from the Denver-Julesburg basin in Weld County, Colorado can access the system through the Front Range Pipeline, which is owned by third parties.

Customers. Our gathering, processing and transportation business serves customers predominantly in the Gulf Coast region of the United States and includes both upstream customers and purchasers of natural gas and NGLs. Upstream customers served by our systems primarily consist of small, medium and large independent operators and large integrated energy companies, while our natural gas customers primarily consist of large users of natural gas, such as power plants, industrial facilities, local distribution companies and other large consumers. Our condensate and NGLs are marketed to chemical facilities, refiners, various third parties and end users. Due to the cost of making physical connections from the wellhead to gathering systems, the majority of our customers tend to renew their gathering and processing contracts with us rather than seeking alternative gathering and processing services.

Supply and Demand. Demand for our gathering, processing and transportation services primarily depends upon the supply of natural gas reserves and associated natural gas from crude oil development and the drilling rate for new wells. The level of impurities in the natural gas gathered also affects treating services. All of our gathering, processing and transportation systems exist in regions that have shale or tight sands formations where hydraulic fracturing technology can be utilized to increase production from the natural gas wells. Demand for these services depends upon overall economic conditions, drilling activity and the prices of natural gas, NGLs, and condensates. Commodity prices for natural gas, NGLs, and condensates remained low throughout 2016. As a result, there has been reduction in drilling activity by producers and reduced volumes on the systems we operate. Our existing systems are located in basins that have the opportunity to grow in an improved pricing environment.

Competition. Competition in our gathering, processing and transportation business is significant in all of the markets we serve. Competitors include interstate and intrastate pipelines or their affiliates and other midstream businesses that gather, treat, process and market natural gas or NGLs. Our gathering business’s principal competitors are other midstream companies and, to a lesser extent, producer-owned gathering systems. Some of these competitors are substantially larger than we are. Because pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipeline companies. Pipelines typically compete with each other based on location, capacity, reputation, price and reliability.

 

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Competition for the services we provide varies based upon the location of gathering, treating and processing facilities. Most upstream customers have alternate gathering, treating and processing facilities available to them. In addition, they have alternatives such as building their own gathering facilities or, in some cases, selling their natural gas supplies without treating and processing. On sour natural gas systems, such as parts of our East Texas system, competition is more limited in certain locations due to the infrastructure required to treat sour natural gas. Many of the large wholesale customers we serve have multiple pipelines connected or adjacent to their facilities. Accordingly, many of these customers have the ability to purchase natural gas directly from a number of pipelines or third parties that may hold capacity on the various pipelines. In addition, several new interstate natural gas pipelines have been constructed in areas currently served by our natural gas transportation pipelines. Some of these new pipelines may compete for customers with our existing pipelines.

Logistics and Marketing

The primary role of our logistics and marketing business is to provide marketing services of natural gas, NGLs and condensate received from our gathering, processing and transportation business. We purchase and receive natural gas, NGLs and other products from pipeline systems and processing plants and sell and deliver them to wholesale customers, such as distributors, refiners, fractionators, chemical facilities, various third parties and end users. Our Logistics and Marketing segment derives a majority of its operating income from selling natural gas, NGLs and condensate received from producers on our Gathering, Processing and Transportation segment pipeline assets. A majority of the natural gas and NGLs we purchase are produced in Texas markets where we have intrastate deliverability alternatives over the past several years. We use our connectivity to interstate pipelines to improve value for the producers by delivering natural gas into premium markets and NGLs to primary markets where we sell them to major customers. Additionally, our Logistics and Marketing segment derives operating income from providing logistics services for our customers from the wellhead to markets.

On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Logistics and Marketing segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third party. From that date through October 2016, Midcoast Operating subsidiaries sold their natural gas products directly to third parties instead of a portion through the Logistics and Marketing segment. The arrangement for Midcoast Operating subsidiaries to sell natural gas products directly to third parties expired on October 31, 2016. Since that date, Midcoast Operating subsidiaries have sold their natural gas products to third parties through the Logistics and Marketing segment.

On August 15, 2016, our logistics and marketing business sold its transport trucks and trailers (alternatively “our trucking business”) to a third party. In conjunction with the sale, our logistics and marketing business entered into a long-term trucking services agreement with the purchaser, insuring no interruption of our logistics activities.

As of December 31, 2016, the physical assets of our logistics and marketing business primarily consist of:

 

    Approximately 190 railcars for transporting NGLs;

 

    Our TexPan liquids railcar facility near Pampa, Texas; and

 

    Our Petal truck & rail facility near Hattiesburg, Mississippi.

We also enter into agreements with various third parties to obtain natural gas and NGL supply, transportation, gas balancing, fractionation and storage capacity in support of the logistics and marketing services we provide to our gathering, processing and transportation business and to third-party customers. These agreements provide our logistics and marketing business with the following:

 

    up to approximately 79,000 Bpd through 2022 of firm NGL fractionation capacity;

 

    up to approximately 75,000 Bpd on average in 2017 to 120,000 Bpd in 2022 of firm NGL transportation capacity on the Texas Express NGL system;

 

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    up to approximately 39,000 Bpd through 2022 of additional firm NGL transportation capacity on third-party pipelines;

 

    up to approximately 42,555 Bpd through April 2017 and 8,500 Bpd continuing May 2017 through March 2019 of NGL capacity via exchange agreements with various counterparties; and

 

    approximately 5.0 million barrels of liquids, or MMBbls, of NGL storage capacity.

Customers. Our logistics and marketing business purchases and receives natural gas, NGLs and other products from our gathering, processing and transportation business as well as from third-party pipeline systems and processing plants and sells and delivers them to third-party customers. Most of the third-party customers of our logistics and marketing operations are wholesale customers, refiners and petrochemical producers, fractionators, propane distributors and industrial, utility and power plant customers. In addition, we sell natural gas and NGLs to marketing companies at various market hubs.

Supply and Demand. Supply for our logistics and marketing business depends to a large extent on the natural gas reserves, associated natural gas from crude oil development, and rate of drilling within the areas served by our gathering, processing and transportation business. Demand is typically driven by a number of factors such as physical domestic and international industrial requirements.

Since major market hubs for natural gas and NGLs and related products are located in the Mid-Continent and Gulf Coast regions of the United States and our logistics and marketing business assets are geographically located within Texas, Louisiana, Oklahoma, Kansas and Mississippi, the majority of activities conducted by our logistics and marketing business are conducted within those states. Our interconnected gathering and transportation systems and our long-term trucking and railcar arrangements mitigate the risk that our natural gas and NGLs will be shut in by capacity constraints on downstream NGL pipelines and other facilities.

One of the key components of our logistics and marketing business is our natural gas and NGL purchase and resale activities. Through our natural gas and NGL purchase and resale services, we can efficiently manage the transportation and delivery of natural gas from our gathering, processing and transportation assets and deliver them to on-system industrial customers, and NGLs to marketing companies at various market hubs. We typically price our sales based on multiple published daily or monthly price indices. In addition, sales to wholesale customers include a pass-through charge for costs of transportation and additional margin to compensate us for the associated services we provide.

Our NGL logistics and marketing business also uses third-party storage facilities for the right to store NGLs for various periods of time to mitigate risk associated with sales and purchase contracts. We have also entered into multiple long-term fractionation contracts with third-party fractionators to provide access to fractionation capacity for our customers.

Competition. Our logistics and marketing business has numerous competitors, including large natural gas and NGL marketing companies, marketing affiliates of pipelines, major oil, natural gas and NGL producers, trucking, railcar and pipeline operations, independent aggregators and regional marketing companies. Our logistics and marketing business’ principal competitors include numerous natural gas and NGL marketing companies and major integrated oil and natural gas companies.

Seasonality

The drilling activities of producers within our areas of operations generally do not vary materially by season but may be affected by adverse weather. Generally, the demand for natural gas and NGLs decreases during the spring and fall months and increases during the winter months and, in some areas, during the summer months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. Demand for natural gas with respect to power plant customers is typically driven by weather-related factors.

 

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REGULATION

Regulation of Intrastate Natural Gas Pipelines

Our operations in Texas are subject to regulation under the Texas Utilities Code and the Texas Natural Resources Code, as implemented by the Texas Railroad Commission, or TRRC. Generally, the TRRC is vested with authority to ensure that rates charged for natural gas sales and transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law, unless challenged in a complaint. We cannot predict whether such a complaint may be filed against us or whether the TRRC will change its method of regulating rates. Pursuant to authority granted to it by the Texas Natural Resources Code, the TRRC has adopted by rule an Informal Complaint Process that applies to rate issues associated with gathering or transmission systems, thus subjecting gathering and intrastate pipeline activities of Enbridge to the jurisdiction of the TRRC.

In Oklahoma, intrastate natural gas pipelines and gathering systems are subject to regulation by the Oklahoma Corporation Commission, or OCC. Specifically, the OCC is vested with the authority to prescribe and enforce maximum rates for the transportation and transmission of natural gas. These rates may be amended or altered at any time by the OCC. However, a company affected by a rate change will be given at least ten days’ notice in order to introduce evidence of opposition to such amendment. Adjustment of claims or settlement of controversies regarding rates between transportation and transmission companies and customers will be mediated by the OCC prior to any hearing on the dispute, upon request. An entity operating an intrastate natural gas pipeline or gathering system in Oklahoma is subject to the jurisdiction of the OCC, and failure to comply with an OCC order regarding rate requirements could result in contempt proceedings instituted before the OCC by any affected party.

Regulation by the FERC of Intrastate Natural Gas Pipelines

Our Texas and Oklahoma intrastate pipelines are generally not subject to regulation by the Federal Energy Regulatory Commission, or FERC. However, to the extent our intrastate pipelines transport natural gas in interstate commerce, the rates, terms and conditions of such transportation are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA. In addition, under FERC regulations we are subject to market manipulation and transparency rules. This includes the annual reporting requirements pursuant to FERC Order No. 735 et al. Failure to comply with the FERC’s rules, regulations and orders can result in the imposition of administrative, civil and criminal penalties.

Natural Gas Gathering Regulation

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from the jurisdiction of the FERC. We own certain natural gas facilities that we believe meet traditional tests the FERC has used to establish a facility’s status as a gatherer not subject to FERC jurisdiction. However, to the extent our gathering systems buy and sell natural gas that is processed or that can be sold into the market without being processed, such gatherers, in their capacity as buyers and sellers of natural gas, are subject to certain reporting requirements resulting from the FERC Order 704 series.

State regulations of gathering facilities typically address the safety and environmental concerns involved in the design, construction, installation, testing and operation of gathering facilities. In addition, in some circumstances, nondiscriminatory requirements are also addressed; however, state regulators have not historically taken an active role in setting or reviewing rates for gathering facilities absent a shipper protest. Many of the producing states have previously adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access or perceived rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to significant and unduly burdensome state or federal regulation of rates and services.

 

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NGL Pipeline Regulation

The mainline and gathering portions of the Texas Express NGL system are common carriers subject to regulation by various federal agencies and/or the TRRC. The FERC regulates the interstate pipeline transportation of crude oil, petroleum products, and other liquids such as NGLs, collectively called “petroleum pipelines.” The FERC regulates these operations pursuant to the Interstate Commerce Act, or ICA, and the Energy Policy Act of 1992, or EP Act of 1992. The ICA and its implementing regulations require that tariff rates for interstate service on petroleum pipelines be just and reasonable and must not be unduly discriminatory or confer undue preference on any shipper.

The EP Act of 1992 required the FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, the FERC adopted an indexed rate methodology. If the rate levels on Texas Express NGL system were subject to formal review or challenge before the FERC, the Texas Express NGL system would be required to produce a traditional cost of service review justifying its revenues or demonstrate it lacks significant market power.

Two of our other NGL lines, which do not provide service to third parties, operate under FERC-granted waivers from the reporting requirements of Sections 6 and 20 of the ICA. These waivers are effective until a third party shipper requests service. In addition, certain of our NGL lines are subject to regulation as a common carrier by the TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates we charge for NGL transportation service are deemed just and reasonable under Texas law unless challenged by a complaint. Complaints to state agencies remain infrequent and are usually informally resolved, but ongoing industry practices might indicate an increase in complaints and TRRC oversight. Although we cannot assure that our intrastate rates would ultimately be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

Sales of Natural Gas, Condensate and Natural Gas Liquids

The price at which we sell natural gas currently is not subject to federal or state regulation except for certain systems in Texas. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and to facilitate price transparency in markets for the wholesale sale of physical natural gas.

Our sales of condensate and NGLs currently are not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC’s or TRRC’s jurisdiction. Regulations implemented by the FERC or TRRC could increase the cost of transportation service on certain petroleum products pipelines, however, we do not believe that these regulations will affect us any differently than other marketers of these products transporting on regulated pipelines.

Safety and Environmental Regulation

General

Our transmission and gathering pipelines, storage and processing facilities, and railcar operations are subject to extensive environmental, operational and safety regulation at federal and state levels. The added costs imposed by regulations are generally no different than those imposed on our competitors. Failure to comply with such standards and regulations can result in substantial penalties and/or enforcement actions and added operational costs.

 

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Pipeline Safety and Transportation Regulation

Some of our natural gas pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002, or PSIA, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas, or HCAs. HCAs are defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management.

Our NGL pipelines are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979, or the HLPSA, and the Pipeline Safety Act of 1992, or the PSA. The HLPSA requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline. The PSA added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs.

Our pipelines are also subject to the Accountable Pipeline Safety and Partnership Act of 1996, or the APSA, which limited the operator identification requirement to operators of pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel.

PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:

 

    perform ongoing assessments of pipeline integrity;

 

    identify and characterize applicable threats to pipeline segments that could impact a HCA;

 

    improve data collection, integration and analysis;

 

    repair and remediate pipelines as necessary; and

 

    implement preventive and mitigating actions.

Although many of our pipeline facilities are not classified as transmission pipelines and currently are not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our transmission pipelines on an annual basis as required by existing United States Department of Transportation, or DOT, regulations and their state counterparts. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that we expand our integrity management program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on our operations.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes

 

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additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs.

The PHMSA finalized a rule increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. The PHMSA also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. The PHMSA has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. The PHMSA also has published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrostatic tests of our facilities to confirm the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

We have incorporated all existing requirements into our programs by the required regulatory deadlines, and are continually incorporating the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs.

When hydrocarbons are released into the environment or violations identified during an inspection, PHMSA may issue a civil penalty or enforcement action, which can require internal inspections, pipeline pressure reductions and other methods to manage or verify the integrity of a pipeline in the affected area. In addition, the National Transportation Safety Board may perform an investigation of a significant accident to determine the probable cause and issue safety recommendations to prevent future accidents.

We believe that our pipeline and railcar operations are in substantial compliance with applicable operational and safety requirements. In instances of non-compliance, we have taken actions to remediate the situations.

 

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Nevertheless, significant operating expenses and capital expenditure could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the capabilities of our current pipeline control system or other safety equipment.

Environmental Regulation

General. Our operations are subject to complex federal, state and local laws and regulations relating to the protection of health and the environment, including laws and regulations that govern the handling, storage, treating and processing of liquid hydrocarbon materials or emissions from natural gas processing, treating or compression facilities. As with the pipeline and processing industry in general, complying with current and anticipated environmental laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position since the operations of our competitors are generally similarly affected.

In addition to compliance costs, violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions, banning or delaying certain activities. We believe that our operations are in substantial compliance with applicable environmental laws and regulations.

There are also risks of accidental releases into the environment associated with our operations, such as releases or spills of crude oil, natural gas liquids, natural gas or other substances from our pipelines or facilities. Such accidental releases could, to the extent not insured, subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines, penalties or damages for related violations of environmental laws or regulations.

Although we are entitled, in certain circumstances, to indemnification from third parties for environmental liabilities relating to assets we acquired from those parties, these contractual indemnification rights are limited, and accordingly, we may be required to bear substantial environmental expenses. However, we believe that through our due diligence process, we identify and manage substantial issues.

Air and Water Emissions. Our operations are subject to the Clean Air Act, or CAA, and the Clean Water Act, or CWA, and comparable promulgated state and local statutes. We anticipate, therefore, that we will incur costs in the next several years for air pollution control equipment and spill prevention measures in connection with maintaining existing facilities, designing future compliant facilities and obtaining permit approvals for any new or acquired facilities. Our facilities subject to criteria air emission inventories have reported that they are in compliance with state mandated timelines. The operations of our compressor and plant facilities subject to the Environmental Protection Agency’s, or EPA, Spill Prevention, Control, and Countermeasures Rule are currently in full compliance. Our facilities subject to existing EPA Part 98 Subpart C and W Greenhouse Gas Reporting Program, or GHGRP, rules have reported emissions prior to the annual filing deadlines.

On October 31, 2016, the EPA finalized rule revisions, Subpart JJJJ, in the Code of Federal Regulations, or CFR, relating to test methods and performance specifications impacting facilities with stationary spark ignition internal combustion engines.

On September 18, 2015, the EPA published a proposed rule, Subpart OOOOa, which would update the original 2012 standard to include additional reductions in methane and VOCs in the oil and gas industry. On June 3, 2016, EPA published NSPS OOOOa in the Federal Register which includes seven areas of applicability for previously unaffected sources. On July 15, 2016 fifteen states filed suit in the District of Columbia Circuit Court objecting the rule. The current compliance date for OOOOa is June 2017.

 

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On October 22, 2015, the EPA responded to a petition made by the Environmental Integrity Project to include the oil and gas extraction industrial sector in the scope of covered sectors of Section 313 of the Emergency Planning and Community Right-to-Know Act, commonly known as the Toxic Release Inventory, or TRI. EPA has currently indicated oil and gas extraction is not included in the TRI reporting screening program.

On October 22, 2015, the EPA finalized amendments to GHGRP to include natural gas gathering and boosting systems, well completions, and blowdown emissions associated with transmission pipelines. The rule effective date for data collection was January 1, 2016 and reporting begins for calendar year 2017 for applicable facilities.

The EPA has issued the Oil and Gas Information Request, or ICR, scoped to the oil and gas industry. MEP received notification of ICR on November 22, 2016 in which EPA will ask the oil and gas industry members to provide extensive information for EPA to develop regulations to further reduce methane and VOC emissions. EPA responses are due 180 days from receipt of the mailed ICR document.

On June 29, 2015, the EPA published the Clean Water Rule: Definition of “Waters of the United States.” The new rule is intended to clarify what is considered Waters of the United States, or WOTUS, with respect to discharges of pollutants to the covered water. The Oil Pollution Act, or OPA, was enacted in 1990 and amends parts of the CWA and other statutes as they pertain to the prevention of and response to oil spills. Under the OPA, we could be subject to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill from our facilities into navigable waters, along shorelines or in an exclusive economic zone of the United States. The OPA also imposes certain spill prevention, control and countermeasure requirements for many of our non-pipeline facilities, such as the preparation of detailed oil spill emergency response plans and the construction of dikes or other containment structures to prevent contamination of navigable or other waters in the event of an oil overflow, rupture or release. For our liquid pipeline facilities, the OPA imposes requirements for emergency plans to be prepared, submitted and approved by the DOT. For our non-transportation facilities, such as storage tanks that are not integral to our pipeline transportation system, the OPA regulations are promulgated by the EPA. We believe that we are in material compliance with these laws and regulations.

For all proposed rules, we will continue to track the progress through involvement in industry groups and will comply with regulatory requirements. We do not expect a material effect on our financial statements as a result of compliance efforts.

Hazardous Substances and Waste Management. The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA (also known as the “Superfund” law) and similar state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons, including the owners or operators of waste disposal sites and companies that disposed or arranged for disposal of hazardous substances found at such sites. We may generate some wastes that fall within the definition of a “hazardous substance.” We may, therefore, be jointly and severally liable under CERCLA for all or part of any costs required to clean up and restore sites at which such wastes have been disposed. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws may apply to a broader range of substances than CERCLA and, in some instances, may offer fewer exemptions from liability. We have not received any notification that we may be potentially responsible for material cleanup costs under CERCLA or similar state laws.

Site Remediation. We own and operate a number of pipelines, gathering systems, storage facilities and processing facilities that have been used to transport, distribute, store and process natural gas and other petroleum products. Many of our facilities were previously owned and operated by third parties whose handling, disposal and release of petroleum and waste materials were not under our control. The age of the facilities, combined with the past operating and waste disposal practices, which were standard for the industry and regulatory regime at the

 

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time, have resulted in soil and groundwater contamination at some facilities due to historical spills and releases. Such contamination is not unusual within the natural gas and petroleum industry. Historical contamination found on, under or originating from our properties may be subject to CERCLA, the Resource Conservation & Recovery Act and analogous state laws as described above.

Under these laws, we could incur substantial expense to remediate such contamination, including contamination caused by prior owners and operators. In addition, our General Partner could also be liable for such costs to the extent that we are unable to fulfill our obligations. We have conducted site investigations at some of our facilities to assess historical environmental issues, and we are currently addressing soil and groundwater contamination at various facilities through remediation and monitoring programs, with oversight by the applicable governmental agencies where appropriate.

EMPLOYEES

We are managed and operated by the board of directors and executive officers of our General Partner. Neither we nor our subsidiaries have any employees. Affiliates of our General Partner provide the employees and other personnel necessary to conduct our operations. We believe that our General Partner and its affiliates have a satisfactory relationship with those employees.

INSURANCE

Our operations are subject to many hazards inherent in the midstream industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We are insured under the comprehensive insurance program that is maintained by Enbridge for its subsidiaries. The policy includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and has a renewal date of May 1, 2017. The insurance coverage also includes property insurance coverage on our assets that includes earnings interruption resulting from an insurable event, except for pipeline assets that are not located at water crossings. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement we have entered into with EEP, Enbridge and other Enbridge subsidiaries.

The insurance policy coverage limits and deductible amounts at December 31, 2016, for Enbridge, Inc. and its subsidiaries are:

 

Insurance Type

   Coverage Limits      Deductible Amount  
     (in millions)  

Property and business interruption

     Up to $650.0      $ 10.0  

General liability

     Up to $900.0      $ 0.1  

Pollution liability (as included under General Liability)

     Up to $900.0      $ 30.0  

We can make no assurance that the insurance coverage we maintain will be available or adequate for any particular risk or loss or that we will be able to maintain adequate insurance in the future at rates we consider reasonable. Although we believe that our assets are adequately covered by insurance, a substantial uninsured loss could have a material adverse effect on our financial position, results of operations and cash flows.

TAXATION

We are not a taxable entity for U.S. federal income tax purposes. Generally, U.S. federal and state income taxes on our taxable income are borne by our individual partners through the allocation of our taxable income. In

 

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a limited number of states, an income tax is imposed upon us and generally, not our individual partners. The income tax that we bear is reflected in our consolidated financial statements. The allocation of taxable income to our individual partners may vary substantially from net income reported in our consolidated statements of income.

AVAILABLE INFORMATION

We make available free of charge on or through our Internet website http://www.midcoastpartners.com our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not part of this report.

 

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Item 1A. Risk Factors

We encourage you to consider carefully the risk factors described below, in addition to the other information contained in or incorporated by reference into this Annual Report on Form 10-K. The information under “Risks Related to the Merger” relates to the recently announced Merger Agreement pursuant to which EECI, subject to the terms and conditions thereof, will acquire each publicly held Class A common unit for $8.00 per unit in cash. For additional information on the Merger, refer to Part II, Item 8. Financial Statements and Supplementary Data, Note 1, Organization and Nature of Operations. The information under “Risks Related to our Business,” “Risks Inherent in an Investment in Us” and “Tax Risks to Common Unitholders” relates to general risks associated with our business and an investment in our common units and will continue to be applicable to unit holders until such time as the Merger is completed.

Risks Related to the Merger

MEP is subject to provisions that limit its ability to pursue alternatives to the Merger, and we may be limited in our ability to pursue other attractive business opportunities.

Under the Merger Agreement, MEP is restricted from entering into alternative transactions. Unless and until the Merger Agreement is terminated or the Merger is completed, subject to specified exceptions, MEP is restricted from directly or indirectly, soliciting, initiating, knowingly facilitating, knowingly encouraging or knowingly inducing or negotiating, any inquiry, proposal or offer for a competing acquisition proposal with any person. Under the Merger Agreement, in the event of a potential change by the General Partner’s board of directors, in consultation with its conflicts committee, of its recommendation with respect to the Merger in light of a superior proposal, MEP must provide EECI with five days’ notice to allow EECI to propose an adjustment to the terms and conditions of the Merger Agreement. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of MEP from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher per unit market value than the market value of the consideration proposed to be received or realized in the Merger.

In addition to the economic costs associated with pursuing the merger, our General Partner’s management may be required to devote substantial time and other resources to the proposed transaction and related matters, which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, standalone projects and other transactions. If we are unable to pursue such other attractive business opportunities, our growth prospects and the long-term strategic position of our business could be adversely affected.

We may be subject to class action lawsuits relating to the Merger, which could materially adversely affect our business, financial condition and operating results or prevent or delay completion of the Merger.

Our directors and officers may be subject to class action lawsuits relating to the Merger, and other additional lawsuits that may be filed. Such litigation is common in connection with acquisitions of public companies, regardless of any merits related to the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results. In addition, the attention of our management may be diverted to the Merger and related lawsuits rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

One of the conditions to consummating the Merger is that no injunction or other order prohibiting or otherwise preventing the consummation of the Merger transactions shall have been issued by any court or governmental entity of competent jurisdiction in the United States. Consequently, if any lawsuit is filed challenging the Merger and is successful in obtaining an injunction preventing the parties to the Merger Agreement from consummating the Merger, such injunction may prevent the Merger from being completed in the expected timeframe, or at all.

 

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Failure to complete, or significant delays in completing, the Merger with EECI could negatively affect the trading prices of our common units and our future business and financial results.

The Merger with EECI is a taxable transaction and the resulting tax liability of an MEP unitholder, if any, will depend on each such MEP unitholder’s particular situation.

The receipt of cash as Merger consideration in exchange for our common units in the Merger will be treated as a taxable sale by such common unitholders of such common units for U.S. federal income tax purposes. The amount of gain or loss recognized by each unitholder in the Merger will vary depending on each unitholder’s particular situation, including the amount of cash received by each unitholder as Merger consideration in the Merger, the adjusted tax basis of the common units exchanged by each unitholder in the Merger, and the amount of any suspended passive losses that may be available to a particular unitholder to offset a portion of any gain recognized by the unitholder.

Risks Related to our Business

We may not generate sufficient distributable cash flow to support quarterly distributions, at the current level or any level, to our unitholders.

We may not generate sufficient distributable cash flow each quarter to support current or any distribution levels. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

    the fees we charge and the margins we realize for our services;

 

    the volume of natural gas and NGLs we gather and transport and the volume of natural gas we process and treat and NGLs we fractionate;

 

    the volume of natural gas, NGLs, and condensates associated with crude oil drilling;

 

    the level of production of natural gas and the resultant market prices of natural gas and NGLs;

 

    realized pricing impacts on our revenue and expenses that are directly subject to commodity price exposure and the effectiveness of our hedging activities with respect to such commodity price exposure;

 

    the market prices of natural gas and NGLs relative to one another, which affects our processing margins;

 

    capacity charges and volumetric fees associated with our transportation services;

 

    long-term commitments on third-party pipelines, storage facilities or fractionation agreements that are above market prices and may go unutilized;

 

    cash settlements of hedging positions;

 

    the level of competition from other midstream energy companies in our geographic markets;

 

    our operating, maintenance and general and administrative costs, including reimbursements to our General Partner and its affiliates;

 

    regulatory action affecting the supply of, or demand for, natural gas, the maximum transportation rates we can charge on our pipelines, our existing contracts, our operating costs or our operating flexibility;

 

    damage to pipelines, facilities, plants, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism, including damage to third party pipelines or facilities upon which we rely for transportation services;

 

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    outages at the processing, treating or fractionation facilities owned by us or third parties caused by mechanical failure and maintenance, construction and other similar activities;

 

    leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

 

    new legislative and regulatory requirements regarding environment and safety that could result in increased capital expenditures and operating costs, reduce demand for our services or otherwise interrupt our natural gas and NGL supply, which may adversely impact our cash flows and results of operations; and

 

    prevailing economic and market conditions.

In addition, the actual amount of distributable cash flow we generate will also depend on other factors, some of which are beyond our control, including:

 

    the level and timing of capital expenditures we make;

 

    the cost of acquisitions, if any;

 

    our debt service requirements and other liabilities;

 

    fluctuations in our working capital needs;

 

    our ability to borrow funds and access capital markets;

 

    restrictions on distributions contained in our debt agreements;

 

    the amount of cash reserves established by our General Partner; and

 

    other business risks affecting our cash levels.

Although we have an agreement in place through 2017 with EEP to support coverage of any declared distributions up to the quarterly rate of $0.3575 per limited partner unit, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to declare quarterly cash distributions in this or any other amount, and our General Partner has considerable discretion to determine the amount of our available cash each quarter. In addition, our General Partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. Therefore, notwithstanding the agreement in place with EEP, a failure to generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution, or any distribution, could adversely impact the distributions that are made to our unit holders.

Our financial performance could be adversely affected if our assets are used less. Any decrease in the volumes of natural gas or NGLs that we gather or transport or in the volumes of natural gas that we process and treat, or NGLs that we fractionate, could adversely affect our financial condition, results of operations and cash flows.

Our financial performance depends to a large extent on the volumes of natural gas and NGLs processed, treated, fractionated and transported on our systems. Decreases in the volumes processed, treated, fractionated and transported by our systems can directly and adversely affect our revenues and results of operations. These volumes can be influenced by factors beyond our control, including:

 

    decreased drilling activity due to fluctuations in commodity prices, including the price of natural gas and NGL prices;

 

    environmental or other governmental regulations;

 

    competition;

 

    weather conditions;

 

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    storage levels;

 

    alternative energy sources;

 

    decreased demand for natural gas and NGLs;

 

    economic conditions;

 

    supply disruptions;

 

    availability of supply connected to our systems; and

 

    availability and adequacy of infrastructure to move, treat and process supply into and out of our systems.

The volumes of natural gas and NGLs processed, treated, fractionated and transported on our systems also depends on the supply of natural gas, NGLs, and condensate from the producing regions that supply these systems. Supply of natural gas and NGLs can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (1) the level of successful drilling activity in our areas of operation, (2) our ability to compete for volumes from successful new wells and (3) our ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment. In addition, existing customers may not extend their contracts for a variety of reasons, including a decline in the availability of natural gas from the Mid-Continent, United States Gulf Coast and East Texas producing regions or if the cost of transporting natural gas from other producing regions through other pipelines into the markets served by our systems were to render the delivered cost of natural gas or NGLs on our systems uneconomical. If we are unable to find additional customers to replace lost demand or transportation fees, or if we are unable to find new sources of supply to maintain the current levels of throughput on our systems, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders could be materially and adversely affected.

Natural gas and liquid hydrocarbon prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and liquid hydrocarbons relative to one another, could adversely affect our total segment margin and cash flow and our ability to make cash distributions to our unitholders.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. The prices of natural gas, liquid hydrocarbons and other commodities have been extremely volatile, and we expect this volatility to continue. Our future cash flow may be materially adversely affected if we experience significant, prolonged pricing deterioration. For example, if there is a significant change in the relative prices of NGLs, condensate, crude oil, and/or natural gas, it will impact our processing margins, which are a significant component of our ability to generate cash for distribution to our unitholders.

The markets for and prices of natural gas, liquid hydrocarbons and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

 

    the levels of domestic production and consumer demand;

 

    the availability of transportation systems with adequate capacity;

 

    the volatility and uncertainty of regional pricing differentials;

 

    the price and availability of alternative fuels;

 

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    the effect of energy conservation measures;

 

    the nature and extent of governmental regulation and taxation;

 

    fluctuations in demand from electric power generators and industrial customers;

 

    the anticipated future prices of oil, natural gas, NGLs and other commodities;

 

    worldwide political events, including actions taken by foreign oil and natural gas producing nations;

 

    worldwide weather events and conditions, including natural disasters and seasonal changes; and

 

    worldwide economic conditions.

Margins we would have realized from processing activities under certain of our percentage-of-liquids contracts may be reduced if we are unable to process a portion of the natural gas under these contracts.

Under certain of our percentage-of-liquids contracts, we have guaranteed a fixed recovery of NGLs to our customers. To the extent that the volumes of natural gas delivered to us exceed the processing capacity of our processing plants, we may have to pay those customers the fully processed value of their natural gas even though we were unable to process a portion of their natural gas due to capacity limitations, which could reduce the margins we would have otherwise realized from processing activities under these contracts.

Commodity price volatility and risks associated with our hedging activities could adversely affect our cash flow and our ability to make cash distributions to our unitholders.

Our industry remains in a weak commodity price cycle, which could extend beyond 2017. Our exposure to commodity price volatility is inherent to our natural gas processing activities. Before hedging, approximately 30% of our gross margin attributable to our contracts in which we are paid in kind based on the price of natural gas, natural gas liquids and other petroleum based prices, which excludes unutilized transportation commitments, is expected to be attributable to contracts with some degree of direct commodity price exposure in 2017. We employ a disciplined hedging program to manage this direct commodity price risk.

We have hedged approximately 70% of our direct forecasted commodity cash flow exposure for 2017, which is lower than the over 90% that we hedged in 2016. In addition, our condensate and NGL hedge prices for 2017 are approximately 20% and on average 30% lower than 2016, respectively. Because we are not fully hedged and our hedge positions for 2017 are less favorable than they were for 2016, we will be adversely impacted by commodity price exposure on the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. We have hedged approximately 5% of our direct forecasted commodity cash flow exposure for 2018. As a result of our unhedged exposure and the pricing of our hedge positions, continued low prices or a substantial decline in the prices of these commodities could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders, at all or consistent with past levels.

Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our future cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure, we may be prevented from realizing the full benefits of price increases above the level of the hedges. Our hedging activities can result in substantial losses if hedging arrangements are imperfect or ineffective and our hedging policies and procedures are not followed properly or do not work as intended. Further, hedging contracts are subject to the credit risk that the other party may prove unable or unwilling to perform its obligations under the contracts, particularly during periods of weak and volatile economic conditions. In addition, certain of the financial instruments we use to hedge our commodity risk exposures must be accounted for on a mark-to-market basis. This causes periodic earnings volatility due to fluctuations in commodity prices.

 

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Competition may materially and adversely affect our business and results of operations.

We face competition in our gathering, processing and transportation business, as well as in our marketing and logistics business. Some of our competitors are larger companies that have greater financial, managerial and other resources than we do. Our competitors may expand or construct gathering, processing or transportation systems that would create additional competition for the services we provide to our customers. In addition, many of the large wholesale customers served by our natural gas systems have multiple pipelines connected or adjacent to their facilities. Thus, many of these wholesale customers have the ability to purchase natural gas directly from a number of pipelines or from third parties that may hold capacity on other pipelines. Most natural gas producers and owners have alternate gathering and processing facilities available to them. In addition, they have other alternatives, such as building their own gathering facilities or, in some cases, selling their natural gas supplies without processing. Some of our natural gas and NGL marketing competitors have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do. All of these competitive factors could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

If we fail to balance our purchases of natural gas and our sales of residue gas and NGLs, our exposure to commodity price risk will increase.

We may not be successful in balancing our purchases of natural gas and our sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

Our natural gas assets are primarily located in Texas and Oklahoma. Due to our lack of geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

Our natural gas assets are primarily located in Texas and Oklahoma and we intend to focus our future capital expenditures largely on developing our business in these areas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of geographic diversity, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders than if our operations were more diversified.

Future construction and development costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate, which may limit our ability to make cash distributions.

Our strategy to grow our business contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets. The construction of new assets involves numerous regulatory, environmental, legal, political, materials and labor cost and operational risks that are difficult to predict and beyond our control. As a result, we may not be able to complete our projects at the costs estimated or within the time periods we have projected. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:

 

    using cash from operations;

 

    delaying other planned projects;

 

    incurring additional indebtedness; or

 

    issuing additional equity.

 

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Any or all of these methods may not be available when or in the amounts needed or may adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Our revenues and cash flows may not increase immediately following our expenditure of funds on a particular project. For example, if we build a new pipeline or expand an existing facility, the design, construction, development and installation may occur over an extended period of time and we may not receive any material increase in revenue or cash flow from that project until after it is placed in service and customers begin using the systems. If our revenues and cash flow do not increase at projected levels because of substantial unanticipated delays or other factors, we may not meet our obligations as they become due, and we may need to reduce or reprioritize our capital budget, sell non-strategic assets, access the capital markets or reassess our level of distributions to unitholders to meet our capital requirements.

Our growth strategies may be unsuccessful if we incorrectly predict operating results, or are unable to identify and complete future acquisitions or organic growth projects and integrate acquired or developed assets or businesses.

The acquisition and development of complementary midstream assets are components of our growth strategy. Acquisitions and organic growth projects present various risks and challenges, including:

 

    inability to identify attractive acquisition candidates or negotiate acceptable purchase agreements;

 

    mistaken assumptions about future prices, volumes, revenues and costs, future results of operations or expected cost reductions or other synergies expected to be realized;

 

    a decrease in liquidity as a result of utilizing significant amounts of available cash or borrowing capacity to finance an acquisition or organic growth project;

 

    the loss of critical customers or employees at an acquired business;

 

    the assumption of unknown liabilities for which we may not be fully and adequately indemnified or insured;

 

    the risk of failing to effectively integrate the operations or management of acquired assets or businesses or a significant delay in such integration; and

 

    diversion of management’s attention from existing operations.

In addition, we may be unable to identify acquisition targets and consummate acquisitions in the future. A portion of our strategy to grow our business is dependent on our ability to make acquisitions that result in an increase in distributable cash flow.

Our gathering, processing and transportation contracts subject us to renewal risks.

We gather, purchase, process, treat, compress, transport and sell most of the natural gas and NGLs on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with fixed-fee or fixed-spread contracts may desire to enter into gathering and transportation contracts under different fee arrangements, or a producer with whom we have a natural gas purchase contract may choose to enter into a transportation contract with us and retain title to its natural gas. To the extent we are unable to renew or replace our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders could be materially and adversely affected.

 

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We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our financial condition, results of operations and cash flows.

Some of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets or reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could materially affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected. In addition, total insurance coverage for multiple insurable incidents exceeding coverage limits would be allocated by Enbridge on an equitable basis under an insurance allocation agreement.

Our operations are subject to all of the risks and hazards inherent in the gathering and transportation of natural gas and NGLs and the processing and treating of natural gas and fractionation of NGLs, including:

 

    damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;

 

    inadvertent damage from construction, vehicles, farm and utility equipment;

 

    leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;

 

    ruptures, fires and explosions; and

 

    other hazards, including those associated with high sulfur content natural gas, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. While we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates, including EEP. The comprehensive insurance program also includes property insurance coverage

 

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on our assets, except pipeline assets that are not located at major water crossings, and earnings interruption resulting from an insurable event. In the unlikely event that multiple insurable incidents occur that exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the participating Enbridge entities on an equitable basis based on an insurance allocation agreement that we entered into with EEP, Enbridge and another Enbridge subsidiary.

If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our total segment margin and cash flow and our ability to make cash distributions to our unitholders could be adversely affected.

Our natural gas and NGL gathering and transportation pipelines and natural gas processing and treating facilities and NGL fractionation facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of such third-party pipelines, processing plants, fractionation facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from hurricanes or other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our segment margin and ability to make cash distributions to our unitholders could be adversely affected.

Our ability to access capital markets and credit on attractive terms to obtain funding for our capital projects and acquisitions may be limited.

Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Domestic and international economic conditions affect the functioning of capital markets and the availability of credit. Adverse economic conditions, such as the recent decline and currently depressed levels of commodity prices, have resulted in weakness and volatility in the capital markets, which has limited our ability to raise capital through equity or debt offerings. Upon closing of the Merger, we will no longer have equity securities traded on public markets, which will further limit our ability to obtain funding through equity offerings. Additionally, the availability and cost of obtaining credit commitments from lenders can change as economic conditions and banking regulations reduce the credit that lenders have available or are willing to lend. These conditions, along with significant write-offs in the financial services sector and the re-pricing of market risks, can make it difficult to obtain funding for our capital needs from the capital markets on acceptable economic terms. As a result, we may revise the timing and scope of these projects as necessary to adapt to prevailing market and economic conditions or ability to make distributions.

Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or capital markets on acceptable terms, if needed and to the extent required. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plan, enhance our existing business, complete acquisitions and construction projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Debt we or Midcoast Operating incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Midcoast Operating is party to a Financial Support agreement with EEP as the financial services provider, providing for guaranties of, and letters of credit obtained by, EEP on an aggregate amount not to exceed

 

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$700.0 million. We are also party to a revolving credit agreement and have issued senior notes under a private placement agreement. Our existing and future level of debt, as well as Midcoast Operating’s future level of debt, could have important consequences to us, including the following:

 

    our ability and Midcoast Operating’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, cash distributions or other purposes may be impaired or such financing may not be available on favorable terms;

 

    the funds that we or Midcoast Operating have available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our and Midcoast Operating’s respective cash flow required to make interest payments on outstanding debt;

 

    we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

    our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt and Midcoast Operating’s debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictions in our revolving credit facility and note purchase agreement could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

Our revolving credit facility limits our ability and Midcoast Operating’s ability to, among other things:

 

    incur or guarantee additional debt;

 

    make distributions on or redeem or repurchase units or other limited partner interests during the continuance of a default;

 

    make certain investments and acquisitions;

 

    incur certain liens or permit them to exist;

 

    enter into certain types of transactions with affiliates other than subsidiaries;

 

    merge or consolidate with another company; and

 

    transfer, sell or otherwise dispose of all or substantially all of our or Midcoast Operating’s assets.

Our revolving credit facility and note purchase agreement contain covenants requiring us to maintain certain financial ratios. We are not permitted to allow our ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.

In addition, our revolving credit facility has a covenant that upon certain trigger events, the borrowers and the guarantors will grant liens in their assets (subject to certain excluded assets, such as motor vehicles, stock of certain foreign subsidiaries, and other assets not to exceed 10% of the consolidated tangible assets of the borrowers and guarantors) to secure the obligations under the loan documents. The springing lien trigger events

 

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include, among other things, a trigger after for two consecutive quarters of the total leverage ratio being greater than 4.25 to 1.00, or 4.75 to 1.00 during an acquisition period.

These covenants could limit our ability to undertake additional debt financing. Our ability to meet such financial ratios can be affected by events beyond our control, and we cannot assure that we will meet those ratios. It is likely that we may not meet the total leverage ratio financial covenant at some point during 2017 without further action on our part. If this were to occur, we would seek to take action to prevent a default, although there is no assurance that we would be successful. In addition to the consequences of default noted below, we and Midcoast Operating are restricted under the revolving credit facility from making distributions if there is a continuing default under certain covenants, including the financial covenants.

The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. Failure to comply with the provisions of our revolving credit facility could result in the occurrence of an event of default under the Credit Agreement, which would result in a cross-default under the note purchase agreement relating to the Notes. If an event of default were to occur, the lenders could, among other things, declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our or Midcoast Operating’s debt is accelerated, our assets and Midcoast Operating’s assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

To the extent Midcoast Operating seeks a credit rating and receives less than an investment grade credit rating, or EEP terminates the Financial Support agreement with Midcoast Operating, Midcoast Operating could be required to provide collateral for Midcoast Operating’s hedging liabilities.

Currently, Midcoast Operating is party to certain International Swaps and Derivatives Association, Inc., or ISDA®, agreements associated with the derivative financial instruments we use to manage our exposure to fluctuations in commodity prices. These ISDA® agreements require Midcoast Operating to provide assurances of performance if counterparties’ exposure to Midcoast Operating exceeds certain levels or thresholds. EEP generally provides letters of credit on Midcoast Operating’s behalf to satisfy such requirements. Midcoast Operating and EEP are parties to a Financial Support agreement under which, during the term of the agreement, EEP will provide letters of credit and guarantees in support of Midcoast Operating’s financial obligations under derivative agreements and natural gas and NGL purchase agreements. Under the Financial Support agreement, EEP’s support of Midcoast Operating’s obligations will terminate on the earlier to occur of (1) the fourth anniversary of the closing of our initial public offering, or the Offering, and (2) the date on which EEP owns, directly or indirectly (other than through its ownership interests in us), less than 20% of the total outstanding limited partner interest in Midcoast Operating.

Without an investment grade credit rating or financial support from EEP, we expect that Midcoast Operating will be required to provide letters of credit, cash collateral or other financial assurance with respect to new derivative agreements or purchase agreements that Midcoast Operating enters into. The amounts of any letters of credit Midcoast Operating provides under the terms of Midcoast Operating’s ISDA® agreements or other derivative financial instruments or agreements, or otherwise in support of our operations, would reduce the amount that we are able to borrow under our revolving credit facility. To the extent that EEP no longer provides this financial support or if we were otherwise required to guarantee the obligations currently guaranteed by EEP under the Financial Support agreement, the impact on our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders could be materially and adversely affected.

EEP’s credit ratings could adversely affect our ability to grow our business and our ability to obtain credit in the future.

EEP’s long-term credit ratings are currently investment grade. Although we do not have any indebtedness rated by any credit rating agency, we may have rated debt in the future. Credit rating agencies will likely

 

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consider EEP’s debt ratings when assigning ours because of EEP’s ownership interest in us and control of our operations. If one or more credit rating agencies were to downgrade the outstanding indebtedness of EEP or us, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our financial condition, results of operations and cash flows and our ability to grow our business and to make cash distributions to our unitholders.

Our logistics and marketing operations involve market and regulatory risks.

The primary role of our logistics and marketing business is to provide marketing services of natural gas, NGLs and condensate received from our gathering, processing and transportation businesses, thereby enhancing our competitive position. Our logistics and marketing business purchases natural gas, NGLs and condensate at prices determined by prevailing market conditions. Following our purchase of natural gas, NGLs and condensate, we generally resell the natural gas, NGLs, or condensate under sales contracts that are generally comparable in terms to our purchase contract, including any price escalation provisions. The profitability of our logistics and marketing operations may be affected by the following factors:

 

    our ability to negotiate on a timely basis commodity purchase and sales agreements in changing markets;

 

    reluctance of wholesale customers to enter into long-term purchase contracts;

 

    consumers’ willingness to use other fuels when natural gas, NGL or condensate prices increase significantly;

 

    timing of imbalance or volume discrepancy corrections and their impact on financial results;

 

    the ability of our customers to make timely payment;

 

    inability to match purchase and sale of natural gas, NGLs or condensate on comparable terms;

 

    changes in, limitations upon or elimination of the regulatory authorization required for our wholesale sales of natural gas, NGLs and condensate in interstate commerce; and

 

    long-term commitments on third-party pipelines, storage facilities or fractionation agreements that are above market prices and may go unutilized.

Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could result in significant financial losses.

We use derivative financial instruments to manage the risks associated with market fluctuations in commodity prices, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are associated with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate all risk of unauthorized trading and other speculative activity. Although this activity is monitored independently by our risk management function, we remain exposed to the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detect and prevent all unauthorized trading and other violations of our risk management policies and procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could result in significant financial losses and have a material adverse effect on our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Compliance with environmental and operational safety laws and regulations may expose us to material costs and liabilities.

Our pipeline, gathering and processing operations are subject to federal, state and local laws and regulations relating to environmental protection and operational and worker safety. Numerous governmental authorities have

 

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the power to enforce compliance with the laws and regulations they administer and permits they issue, often imposing complex requirements and necessitating capital expenditures or increased operating costs to achieve compliance, especially when activity is in the presence of sensitive elements like water crossings, wetlands and endangered species. Our failure to comply with these laws, regulations and operating permits can result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Our natural gas gathering, processing and transportation and NGL fractionation operations expose us to the risk of incurring significant environmental and safety-related costs and liabilities. Additionally, operational modifications, including pipeline restrictions, necessary to comply with regulatory requirements and resulting from our handling of natural gas and liquid hydrocarbons, historical environmental contamination, accidental releases or upsets, regulatory enforcement, litigation or safety and health incidents can also result in significant cost or limit revenues and volumes. In addition, environmental and operational safety laws and regulations, including but not limited to pipeline safety, wastewater discharge and air emission requirements, continue to become more stringent over time, particularly those related to the oil and gas industry. We may incur joint and several strict liability under these environmental laws and regulations in connection with discharges or releases of natural gas and liquid hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for gathering or processing activities for a number of years, often by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our natural gas and liquid hydrocarbons are handled or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage. We may also incur costs in the future due to changes in environmental and safety laws and regulations, or re-interpretations of enforcement policies or claims for personal, property or environmental damage. We may not be able to recover these costs from insurance or through higher rates.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

Because our operations, including our processing, treating and fractionation facilities and our compressor stations, are sources of greenhouse gases, legislation and regulations governing greenhouse gas emissions could increase our costs related to operating and maintaining our facilities, and could delay future permitting. At the federal level, the United States Congress has in the past and may in the future consider legislation to impose a tax on carbon or require a reduction of greenhouse gas emissions. On September 22, 2009, the EPA issued a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Subsequently, on November 30, 2010, the EPA issued a supplemental rulemaking that expanded the types of industrial sources that are subject to or potentially subject to the EPA’s mandatory greenhouse gas emissions reporting requirements to include petroleum and natural gas systems. These regulations were amended by the EPA in November 2014.

The EPA has concluded that the April 2010 issuance of regulations to control the greenhouse gas emissions from light duty motor vehicles (the “tailpipe rule”) automatically triggered provisions of the CAA that, in general, could potentially require stationary source facilities that emit more than 250 tons per year of carbon dioxide equivalent to obtain permits to demonstrate that best practices and technology are being used to minimize greenhouse gas emissions. On May 13, 2010, the EPA issued the “tailoring rule,” which served to establish the greenhouse gas emissions threshold for major new (and major modifications to existing) stationary sources. This rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit (Coalition for Responsible Regulation v. EPA), which dismissed the challenge on jurisdictional grounds. On appeal, the U.S. Supreme Court in 2013 (Utility Air Regulatory Group v. EPA) found the rule to be unlawful. Under the approach now being implemented by the EPA, for most purposes, new permitting provisions to control greenhouse gas emissions are required for new major source facilities that also emit 100,000 tons per year or more of carbon dioxide

 

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equivalent, of CO2e, and existing major source facilities making major modifications that also would increase greenhouse gas emissions by 75,000 CO2e. The EPA has indicated in rulemakings that it may further reduce the current regulatory thresholds for greenhouse gas emissions, making additional sources subject to permitting.

Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for us and reduced demand for our services.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement was signed by President Obama on August 26, 2016 and requires participating countries to “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. It is not clear at this time if the Trump Administration will remain committed to the Paris Agreement. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements. Furthermore, the EPA has finalized regulations that impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development, production, and transportation operations. EPA also has finalized regulations to impose greenhouse gas emission on the electric power sector, commonly referred to as the Clean Power Plan which, if implemented, could reduce the demand for fossil fuels. This regulation, however, remains the subject of an ongoing legal challenge and the Trump Administration has indicated that it may revisit, modify or revoke this rule, although the final outcome is uncertain at this time. In addition, almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.

Pipeline operations involve numerous risks that may adversely affect our business and financial condition.

Operation of complex pipeline systems, gathering, treating and processing operations involves many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of the facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes, floods, landslides or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, any of which could also result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. Costs of pipeline seepage over time may be mitigated through insurance, however, if not discovered within the specified insurance time period we would incur full costs for the incident. In addition, we could be subject to significant fines and penalties from regulators in connection with such events. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these catastrophic events could be greater.

 

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Our assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future. In addition, there could be service interruptions due to unknown events or conditions, or increased downtime associated with our pipelines that could have a material and adverse effect on our business and results of operations.

Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets will require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make distributions to our unitholders.

Measurement adjustments on our pipeline system can materially affect our financial condition.

Natural gas and NGL measurement adjustments occur as part of the normal operating conditions associated with our pipelines. The quantification and resolution of measurement adjustments is complicated by several factors including: (1) the significant quantities (i.e., thousands) of measurement meters that we use throughout our systems, primarily around our gathering and processing assets; (2) varying qualities of natural gas and NGLs in the streams gathered and processed through our systems; and (3) variances in measurement that are inherent in metering technologies. Each of these factors may contribute to measurement adjustments that can occur on our systems and may materially affect our results of operations.

Increased regulation of hydraulic fracturing and related activities could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

A significant portion of our customers’ natural gas production is developed from unconventional geological formations, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation has been proposed in Congress to both increase and decrease federal involvement in hydraulic fracturing. Legislative proposals to increase federal involvement primarily include: (i) amending the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection”; (ii) requiring federal permitting and regulatory control of hydraulic fracturing; (iii) requiring disclosure of the chemical constituents of the fluids used in the fracturing process; and (iv) requiring groundwater testing prior to hydraulic fracturing operations. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having finalized a five-year study of the potential impacts of hydraulic fracturing on drinking water resources. The EPA finalized this report in December 2016. In so doing, it described how hydraulic fracturing activities may have the potential to impact drinking water resources and the factors that could influence the frequency and severity of those impacts. Due to significant data gaps, however, the EPA was unable to estimate the national frequency of impacts or to fully characterize the severity of those impacts.

Hydraulic fracturing is also subject to an administrative proposal to increase federal regulation that may impose additional operating costs. The Bureau of Land Management has issued a new rule for hydraulic fracturing on federal and tribal lands. The rule would primarily require: (i) stricter well construction standards; (ii) the identification of “usable water”; (iii) federal preapproval for hydraulic fracturing operations; (iv) storage of hydraulic fracturing fluids in above ground tanks; and (v) public disclosure of hydraulic fracturing chemicals. The rule has been overturned and thrown out by a federal district court, but that ruling is currently the subject of an appeal to the United States Court of Appeals for the Tenth Circuit.

On April 17, 2012, the EPA adopted final rules establishing air emission controls for oil and natural gas production and natural gas processing operations. The rules addressed emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through reduced emission (or “green”) completions. The rules also established new requirements for emissions from compressors, controllers,

 

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dehydrators, storage tanks, gas processing plants, and certain other equipment. In August 2015, the EPA proposed regulations to reduce methane and volatile organic compound emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025. The EPA finalized these regulations on June 3, 2016 which impose additional requirements on new, modified or reconstructed natural gas gathering and production facilities and gas processing plants. In concert with these final requirements, the EPA started the formal process to collect information from the oil and gas industry that would support future rulemaking efforts to regulated greenhouse gas emissions from existing sources. We will incur additional costs related to achieve compliance with new emission limits set forth in EPA’s final regulation as well as inspections and maintenance of several types of equipment used in our operations.

Future regulatory actions also have the potential to impact our operations. The PMSHA has issued several notices of proposed rulemakings in recent years addressing a number of pipeline integrity and safety issues. The adoption of any of these requirements likely would increase our operating costs and possibly require capital expenditures. In October 2015, the EPA reduced the National Ambient Air Quality Standard for ozone from 75 Ppb to 70 Ppb. This regulation could impose additional emission control costs on our operations, although these costs are unclear as the EPA and the states have not yet completed the implementation process and the new standard is subject to an ongoing legal challenge.

These rules and proposals may require a number of modifications to our customers’ and our own operations, including, among other things, the installation of new equipment to control emissions and new integrity management requirements. Compliance with such rules could result in additional costs for us and our customers, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations. While the Trump Administration has indicated strong support for fossil fuel development, the extent to which any of the requirements or proposals are revisited in subsequent rulemaking proceedings remains uncertain

Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. For example, on December 13, 2011, the TRRC adopted the Hydraulic Fracturing Chemical Disclosure Rule implementing a state law passed in June 2011, requiring public disclosure of hydraulic fracturing fluid contents for wells drilled under drilling permits issued after February 1, 2012. Certain states, including the State of Texas, also have taken regulatory action in response to increased seismic activity that in certain cases have been connected to hydraulic fracturing or to saltwater or drilling fluid disposal wells. In addition, at least one municipality in a state in which we operate, the City of Denton, Texas, followed others and attempted to ban hydraulic fracturing activities. This ban was overturned by the Texas Legislature. We cannot predict whether any other legislation or regulation will be enacted and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs, and prohibitions for producers who drill near our pipelines. These factors could reduce the volumes of natural gas and NGLs available to move through our gathering and other systems, which could materially adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Changes in, or challenges to, our rates and other terms and conditions of service could have a material adverse effect on our financial condition and results of operations.

The rates charged by several of our pipeline systems are regulated by the FERC or state regulatory agencies or both. These regulatory agencies also regulate other terms and conditions of the services these pipeline systems provide, including the types of services we may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose, the profitability of our pipeline businesses would suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which if delayed could further reduce our cash flow. Furthermore, competition from other

 

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pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

The majority of our pipelines are not subject to regulation by the FERC; however, a change in the jurisdictional characterization of our assets, or a change in policy, could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

The substantial majority of our pipeline assets are gas-gathering facilities or interests in gas-gathering facilities. Unlike interstate gas transportation facilities, natural gas gathering facilities are exempt from the jurisdiction of the FERC under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some cases non-discriminatory take requirements and complaint-based rate regulation. Although the FERC has not made a formal determination with respect to all of our facilities, we believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.

Our pipeline integrity program may impose significant costs and liabilities on us, while increased regulatory requirements relating to the integrity of our pipeline systems may require us to make additional capital and operating expenditures to comply with such requirements.

The Pipeline Safety Act of 2011 enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002 in a number of significant ways, including:

 

    reauthorizing funding for federal pipeline safety programs, increasing penalties for safety violations and establishing additional safety requirements for newly constructed pipelines;

 

    requiring PHMSA to adopt new appropriate regulations requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities;

 

    requiring operators of pipelines to verify MAOP and report exceedances within five days; and

 

    requiring studies of certain safety issues that could result in the adoption of new regulatory requirements for new and existing pipelines, including changes to integrity management requirements for HCAs, and expansion of those requirements to areas outside of HCAs.

In August 2012, PHMSA published rules to update pipeline safety regulations to address some of the provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA’s enforcement process. While

 

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PHMSA has issued several notices of proposed rulemaking to implement the Pipeline Safety Act, many of these regulations were not finalized before funding expired at the end of 2015. On June 22, 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act became law and reauthorized funding for PHMSA until 2019. In addition to reauthorizing funding, the PIPES Act requires PHMSA to complete the rulemaking requirements set forth in the Pipeline Safety Act of 2011. The PIPES Act also requires, among other things, PHMSA to adopt safety standards for underground natural gas storage facilities and small scale liquefied natural gas pipeline facilities, imposes new reporting requirements on operators of hazardous liquid pipelines, and grants PHMSA to issue emergency orders to address unsafe conditions and practices that constitute imminent hazards.

We may incur significant costs and liabilities resulting from implementing and administering pipeline and asset integrity programs and related repairs.

Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Safety Act of 2006 and the PIPES Act of 2016, the PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

 

    perform ongoing assessments of pipeline integrity;

 

    identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

    maintain processes for data collection, integration and analysis;

 

    repair and remediate pipelines as necessary; and

 

    implement preventive and mitigating actions.

This legislation has resulted in increased penalties for safety violations, additional safety requirements for newly constructed pipelines, new reporting requirements, expanded regulatory authority for PHMSA to address emergency conditions and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. New rules proposed by PHMSA address many areas of this legislation. Extending the integrity management requirements to our gathering lines, among other regulatory requirements being considered by PHMSA, would impose additional obligations on us and could add material cost to our operations.

Our gathering systems and intrastate pipelines are subject to state regulation that could materially and adversely affect our operations and cash flows.

State regulation of gathering facilities includes safety and environmental requirements. Several of our gathering systems are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to our rates and terms and conditions of service. State and local regulation may cause us to incur additional costs or limit our operations, may prevent us from choosing the customers to which we provide service, any or all of which could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

We do not own a majority of the land on which our pipelines are located, which could result in disruptions to our operations.

We do not own a majority of the land on which our pipelines are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid

 

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leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations and our ability to make cash distributions to our unitholders.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Cyber-attacks or security breaches could have a material adverse effect on our business, financial condition or results of operations.

Our business is dependent upon information systems and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we collect and store sensitive data in the ordinary course of our business, including personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. We conduct cyber security audits from time to time and continuously monitor our systems in an effort to mitigate the risk of cyber-attacks or security breaches; however, we do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets. Despite our security measures, our information systems may become the target of cyber-attacks or security breaches (including employee error, malfeasance or other breaches), which could compromise our network or systems and result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations.

The adoption and implementation of statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act provides additional statutory requirements for swap transactions, including energy and interest rate hedging transactions. These statutory requirements must be

 

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implemented through regulations, primarily through the Commodity Futures Trading Commission, or the CFTC. To date, the Dodd-Frank Act provisions have not materially changed the way many of our swap transactions are entered into, as we have been able to continue transacting with existing counterparties in over-the-counter markets or with registered exchanges to meet hedging requirements set forth in our risk policies.

The full impact of the Dodd-Frank Act on our hedging activities as an end user is uncertain at this time, as the CFTC continues to promulgate final regulations for position limits. Although the margin rules have been finalized, the upcoming implementation of key provisions in the margin rules and the finalization of position limit provisions may create new regulatory burdens from these developments in addition to the various business conduct, recordkeeping and reporting rules resulting from the Dodd-Frank Act provisions currently in place. Moreover, longer term, fundamental changes to the swap market as a result of the Dodd-Frank Act requirements could significantly increase the cost of entering into and/or reduce the availability of new or existing swaps.

Depending on the final rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions in circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Our ability to operate our business effectively could be impaired if affiliates of our General Partner fail to attract and retain key management personnel.

We depend on the continuing efforts of the executive officers of our General Partner, all of whom are employees of affiliates of EEP’s general partner. Additionally, neither we nor our subsidiaries have employees. Our General Partner is responsible for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our General Partner, including our President and Principal Executive Officer. The loss of any member of our management or other key employees could have a material adverse effect on our business. Consequently, our ability to operate our business and implement our strategies will depend on the continued ability of affiliates of our General Partner to attract and retain highly skilled management personnel with midstream natural gas industry experience. Competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.

The gathering and transporting of natural gas and NGLs and the processing and treating of natural gas and fractionating of NGLs require skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and

 

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benefit costs with respect to our General Partner’s employees, our results of operations could be materially and adversely affected.

Risks Inherent in an Investment in Us

EEP owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations and has limited duties to us and our unitholders. EEP, Enbridge and our General Partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other unitholders.

EEP, which is controlled by Enbridge Energy Management, L.L.C., or Enbridge Management, through a delegation of control agreement with EEP’s general partner, controls our General Partner, and appoints all of the officers and directors of our General Partner, some of whom are also officers or directors of EEP’s general partner, Enbridge Management or Enbridge. Although our General Partner has a duty to manage us in a manner that it believes is in the best interests of our partnership and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that they believe is in the best interests of EEP. Conflicts of interest may arise between EEP, Enbridge and their affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates, including EEP or Enbridge, over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

 

    neither our partnership agreement nor any other agreement requires EEP or Enbridge to pursue a business strategy that favors us;

 

    our General Partner is allowed to take into account the interests of parties other than us, such as EEP and Enbridge, in resolving conflicts of interest;

 

    our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties limiting our General Partner’s liabilities and restricting remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

 

    except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;

 

    affiliates of our General Partner, including EEP and Enbridge, may compete with us, and neither our General Partner nor its affiliates have any obligation to present business opportunities to us;

 

    EEP is under no obligation to offer us any additional interests in Midcoast Operating;

 

    our General Partner will determine the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

    our General Partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce operating surplus. This determination can affect the amount of available cash from operating surplus that is distributed to our unitholders and to our General Partner and the amount of adjusted operating surplus generated in any given period;

 

    our General Partner will determine which costs incurred by it are reimbursable by us;

 

    our General Partner may cause us to borrow funds or take other actions in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing or other action is to make incentive distributions;

 

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    our partnership agreement permits us to classify up to $45.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus and this cash may be used to fund distributions to our General Partner in respect of the general partner interest or the incentive distribution rights;

 

    our partnership agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

    our General Partner intends to limit its liability regarding our contractual and other obligations;

 

    our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units;

 

    our General Partner controls the enforcement of the obligations that it and its affiliates owe to us;

 

    our General Partner decides whether to retain separate counsel, accountants or others to perform services for us; and

 

    our General Partner may elect to cause us to issue Class B common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our General Partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner, including EEP and Enbridge, and result in less than favorable treatment of us and our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we will distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our common unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce our distributable cash flow.

 

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While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement can be amended with the consent of our General Partner and the approval of a majority of the outstanding Class A common units and Class B common units (including Class A common units and Class B common units held by affiliates of our General Partner), voting together as a single class.

Reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce the amount of cash we have available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our General Partner.

Prior to making any distributions to our unitholders, we will reimburse our General Partner and its affiliates, including EEP, for expenses they incur and payments they make on our behalf. Our partnership agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The costs and expenses for which we are required to reimburse our General Partner and its affiliates are not subject to any caps or other limits. The reimbursement of expenses and payment of fees, if any, to our General Partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.

Because our common units are yield-oriented securities, increases in interest rates could adversely impact our unit price and our ability to issue equity or incur debt for acquisitions or other purposes.

As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and the cost to us of any such issuance or incurrence. In addition, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

Our partnership agreement replaces our General Partner’s fiduciary duties to our limited partners with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary duties to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. In addition, our partnership agreement restricts the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable state law. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. When acting in its individual capacity, our General Partner is entitled to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner. By purchasing a common unit, a unitholder is deemed to have consented to the provisions in our partnership agreement, including the provisions discussed above.

Our partnership agreement limits our General Partner’s liabilities and the remedies available to our limited partners for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

   

whenever our General Partner, the board of directors of our General Partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other

 

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action in their respective capacities, our General Partner, the board of directors of our General Partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

    our General Partner will not have any liability to us or our limited partners for decisions made in its capacity as a General Partner so long as it acted in good faith;

 

    our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

    our General Partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by the board of directors or the conflicts committee of the board of directors of our General Partner must be made in good faith and that our conflicts committee and the board of directors of our General Partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our General Partner may elect to cause us to issue Class B common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the conflicts committee of our General Partner’s board or our unitholders. This election may result in lower distributions to our unitholders in certain situations.

Our General Partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Furthermore, our General Partner has the right to transfer all or any portion of the incentive distribution rights at any time, and such transferee shall have the same rights as the General Partner relative to resetting target distributions if our General Partner concurs that the tests for resetting target distributions have been fulfilled. Following a reset election by our General Partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

In the event of a reset of our minimum quarterly distribution and target distribution levels, our General Partner will be entitled to receive, in the aggregate, a number of Class B common units equal to that number of Class B common units that would have entitled the holder of such units to an aggregate quarterly cash distribution in the two-quarter period prior to the reset election equal to the distribution to our General Partner on the incentive distribution rights in the quarter prior to the reset election prior two quarters. Our General Partner will also be issued the number of General Partner units necessary to maintain its General Partner interest in us that existed immediately prior to the reset election (currently 2.0%). We anticipate that our General Partner

 

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would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per Class A common unit without such conversion; however, it is possible that our General Partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our General Partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our General Partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued Class B common units, which, along with the Class A common units, are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the General Partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause holders of our Class A common units and Class B common units to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued Class B common units to our General Partner in connection with resetting the target distribution levels related to our General Partner’s incentive distribution rights.

Unitholders have very limited voting rights and even if they are dissatisfied they currently cannot remove our General Partner without its consent.

Unitholders have only limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our General Partner or the board of directors of our General Partners and will have no right to elect our General Partner or the board of directors or our General Partner on an annual or other continuing basis. The directors of our General Partner are chosen by EEP. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The unitholders will be unable initially to remove our General Partner without its consent because our General Partner and its affiliates will own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding Class A common units and Class B common units voting together as a single class is required to remove our General Partner. Our General Partner and its affiliates own approximately 51.9% of the total outstanding Class A common units and Class B common units on an aggregate basis, excluding common units purchased by directors and officers of our General Partner and Enbridge Management under our directed unit program.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.

Our General Partner units or the control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its General Partner units to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of EEP to transfer its membership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the directors and officers of our General Partner with its own designees.

 

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The incentive distribution rights of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our General Partner transfers its incentive distribution rights to a third party but retains its General Partner interest, our General Partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our General Partner could reduce the likelihood of EEP selling or contributing additional midstream assets to us, as EEP would have less of an economic incentive to grow our business, which in turn could impact our ability to grow our asset base.

We may issue additional partnership securities without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of additional partnership securities without the approval of our unitholders and our existing unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue partnership securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other partnership securities of equal or senior rank will have the following effects:

 

    our existing unitholders’ proportionate ownership interest in us will decrease;

 

    the amount of cash we have available to distribute on each unit may decrease;

 

    because the amount payable to holders of incentive distribution rights is based on a percentage of the total cash available for distribution, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

 

    the ratio of taxable income to distributions may increase;

 

    the relative voting strength of each previously outstanding unit may be diminished; and

 

    the market price of our common units may decline.

EEP may sell our units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of December 31, 2016, EEP holds 1,335,056 Class A common units and 22,610,056 subordinated units. All of the subordinated units were converted into Class B common units on a one-for-one basis on February 15, 2017. Additionally, we have agreed to provide EEP with certain registration rights under applicable securities laws.

Our General Partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our General Partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our General Partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to our unitholders.

Our General Partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 80% of our then-outstanding Class A common units, our General Partner will have the right, but not the obligation, which it may assign to any of its

 

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affiliates or to us to acquire all, but not less than all, of the Class A common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of our Class A common units over the 20 trading days preceding the date that is three business days before the General Partner exercises this right and (2) the highest per-unit price paid by our General Partner or any of its affiliates for Class A common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. They may also incur a tax liability upon a sale of their units. Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of this limited call right. There is no restriction in our partnership agreement that prevents our General Partner from issuing additional Class A common units and exercising its limited call right. If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. Our unitholders could be liable for any or all of our obligations as if they were a general partner if a court or government agency were to determine that:

 

    we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

    a unitholder’s right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our partners if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers or other employees.

Our partnership agreement provides, that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations

 

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or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any of our, or our General Partner’s, directors, officers, or other employees, or owed by our General Partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in our common units is deemed to have received notice of and consented to the foregoing provisions. Although we believe this choice of forum provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against us and our General Partner’s directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings and it is possible that in connection with any action a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action. If a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations and our ability to make cash distributions to our unitholders.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Our Class A common units are listed on the NYSE. The NYSE does not require us to have, and we do not intend to have, a majority of independent directors on the boards of our General Partner or Enbridge Management, or to establish a compensation committee or nominating and corporate governance committee. In addition, any future issuance of additional Class A common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to corporations. Accordingly, holders of our Class A common units will not have the same protections afforded to investor owners of certain corporations that are subject to all of the NYSE corporate governance requirements.

We face risks associated with our and EEP’s review of strategic alternatives.

In light of the extended low commodity price environment and the ongoing challenges it presents to our business, in addition to the Merger, we will continue to work with EEP to explore and evaluate strategic alternatives in addition to, or as alternatives to, our current business strategies to address these challenges. EEP has also indicated that it is reviewing strategic alternatives with respect to its investment in us and Midcoast Operating. The evaluation process is ongoing. There can be no assurance that any such strategic alternatives or initiatives that arise of these reviews will be successful or deliver their anticipated benefits. We may be exposed to new and unforeseen risks and challenges, and it may be difficult to predict the success of such endeavors or the impacts to our unit holders. If we incur significant expenses or divert management, financial and other resources to a strategic alternative or initiative that is unsuccessful or does not meet our expectations, our results of operations and financial condition could be adversely affected. Regardless of the ultimate success of a strategic initiative, the implementation and integration could be disruptive to our current operations and plans.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation for state tax purposes, then our distributable cash flow to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

 

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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a publicly-traded partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

Section 7704 of the Internal Revenue Code of 1986, or the Internal Revenue Code, provides that publicly traded partnerships will, as a general rule, be taxed as corporations. An exception exists, however, with respect to a publicly traded partnership for which 90% or more of the gross income for every taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is qualifying income, we will be taxed as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent tax years. Although we do not believe that we will be treated as a corporation for federal income tax purposes based on our current operations, the IRS could disagree with the positions we take. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax on our gross income apportioned to Texas.

Imposition of any such taxes may substantially reduce the cash we have available for distribution. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation for state tax purposes, there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted that subjects us to taxation as a corporation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships.

Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. It is possible, however, that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

On January 24, 2017, the U.S. Treasury Department issued final regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the final regulations affect our ability to qualify as a publicly traded partnership.

 

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Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to the unitholder. This allocation of taxable income may require the payment of federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we have taken or may take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our positions and such positions may not ultimately be sustained. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our distributable cash flow.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the tax basis of the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, or UBTI, and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in more tax to our unitholders and may adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits

 

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available to our unitholders. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge could also affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Treasury Department has adopted Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of our method. If the IRS were to challenge our method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may be required to recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We have adopted certain valuation methodologies for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our General Partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our General Partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

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The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

As a result of investing in our common units, unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in several states. Most of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is a unitholder’s responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we may elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances and the manner in which the election is made and implemented has yet to be determined. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

 

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Item 2. Properties

The map below presents the location of our current natural gas systems assets, projects being constructed and joint ventures. This map also depicts some assets owned or under development by us to provide an understanding of how they relate to our business.

 

LOGO

Descriptions of these properties of our natural gas systems are included in Item 1. Business, which is incorporated in this Item 2 by reference.

In general, our systems are located on land owned by others and are operated under perpetual easements and rights-of-way, licenses, leases or permits that have been granted by private land owners, public authorities, railways or public utilities. Our natural gas systems have natural gas compressor stations, processing plants and treating plants, the vast majority of which are located on land that is owned by us, with the remainder used by us under easements, leases or permits.

Titles to our properties acquired in our natural gas systems are subject to encumbrances in some cases. We believe that none of these burdens should materially detract from the value of these properties or materially interfere with their use in the operation of our business.

Substantially all of our pipelines are constructed on rights-of-way granted by the record owners of the property. In some instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. Although such revocations are unlikely to be exercised, in nearly all instances continued payment of rentals and license fees, or relocations to accommodate a public authority or railroad ensures

 

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continued operation of the affected system. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.

Under our omnibus agreement, EEP will indemnify us for any failure to have certain rights-of-way, leaseholds, consents, licenses and permits necessary to own and operate our assets in substantially the same manner that they were owned and operated prior to the Offering. EEP’s indemnification obligation is limited to losses for which we notify EEP prior to November 13, 2016 and is subject to a $500,000 aggregate deductible before we are entitled to indemnification and a $15.0 million aggregate cap. During the year ended December 31, 2016, we received indemnification proceeds from EEP under the Omnibus Agreement of $12.2 million for the acquisition of title to right-of-way assets that were pending at the time of our initial public offering and associated legal fees. There have been no other payments from EEP under the Omnibus Agreement.

Item 3. Legal Proceedings

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition. The disclosures included in Part II, Item 8. Financial Statements and Supplementary Data, under Note 24. Commitments and Contingencies, address the matters required by this item and are incorporated in this Item 3 by reference. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 4. Mine Safety Disclosures

None.

 

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our Class A common units are listed and traded on the NYSE, the principal market for the Class A common units, under the symbol “MEP.” The quarterly price ranges per Class A common unit and cash distributions paid per unit for 2016 and 2015 are summarized as follows:

 

     First      Second      Third      Fourth  

2016 Quarters

           

High

   $ 10.09      $ 9.89      $ 9.50      $ 9.07  

Low

   $ 3.76      $ 4.58      $ 6.79      $ 5.30  

Cash distributions paid

   $ 0.3575      $ 0.3575      $ 0.3575      $ 0.3575  

 

     First      Second      Third      Fourth  

2015 Quarters

           

High

   $ 16.00      $ 15.17      $ 13.36      $ 13.58  

Low

   $ 11.41      $ 10.27      $ 8.75      $ 6.50  

Cash distributions paid

   $ 0.3425      $ 0.3475      $ 0.3525      $ 0.3575  

On February 14, 2017, the last reported sales price of our Class A common units on the NYSE was $7.95. As of January 20, 2017, there were four registered holders of record of Class A common units. The number of registered holders does not include unitholders whose units are held in trust by other entities.

On January 26, 2017, we entered into the merger agreement with EECI, an indirect subsidiary of Enbridge Inc., whereby EECI will acquire, for cash, all of our outstanding publicly held common units at a price of $8.00 per common unit for an aggregate transaction value of $170.2 million. The transaction is expected to close in the second quarter of 2017, subject to the satisfaction of customary conditions. Upon closing, we will cease to be a publicly traded partnership and we will cease to be a reporting company under the SEC’s rules and regulations. For further details, refer to Part I, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Overview.

On February 15, 2017, the subordination period ended. On that date, the outstanding subordinated units converted into a new class of common units, which we refer to as Class B common units, on a one-for-one basis, and all Class A common units are no longer entitled to arrearages. For further details, refer to Note 18. Partner’s Capital — Subordinated Units. There is no established public trading market for our Class B common units, all of which are held by EEP.

Our partnership agreement requires us to make quarterly distributions to the holders of our units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our General Partner and its affiliates. However, our General Partner has considerable discretion to determine the amount of our available cash each quarter. For further information about distributions and about limitations and risks related to distributions, please read Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources — Distributions.

On July 29, 2015, the partners of Midcoast Operating approved an amendment to Midcoast Operating’s limited partnership agreement that could enhance our distributable cash flow in certain circumstances. For further information about our funding arrangements with EEP, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Funding Arrangements with EEP.

 

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Item 6. Selected Financial Data

The following table sets forth, for the periods and at the dates indicated, the summary historical financial data of Midcoast Energy Partners, L.P. and our Predecessor. The table is derived, and should be read in conjunction with, our audited consolidated financial statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

    December 31,  
    2016     2015     2014     2013     2012 (1)  
    (in millions, except per unit amounts)  

Income Statement Data: (2)

         

Operating revenues (3)

  $ 1,966.0     $ 2,842.7     $ 5,894.3     $ 5,593.6     $ 5,357.9  

Operating expenses (3)

    2,118.6       3,125.2       5,741.6       5,528.5       5,186.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

    (152.6 )     (282.5 )     152.7       65.1       171.4  

Interest expense, net

    (33.3 )     (29.5 )     (16.7 )     (1.7 )     —    

Equity in earnings of joint ventures

    30.0       29.2       13.2       —         —    

Other income (expense)

    0.9       (0.3 )     (0.3 )     (1.2 )     (0.1 )

Income tax expense

    (2.0 )     (1.4 )     (4.6 )     (8.3 )     (3.8 )
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ (157.0 )   $ (284.5 )   $ 144.3     $ 53.9     $ 167.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Predecessor income prior to initial public offering (from January 1, 2013 through November 12, 2013)

        $ 56.3    
       

 

 

   

Net loss subsequent to initial public offering to Midcoast Energy Partners, L.P. (from November 13, 2013 through December 31, 2013)

        $ (2.4 )  
       

 

 

   

Net income (loss) attributable to noncontrolling interest

  $ (57.1 )   $ (120.6 )   $ 80.2     $ (0.6 )  
 

 

 

   

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.

  $ (99.9 )   $ (163.9 )   $ 64.1     $ (1.8 )  
 

 

 

   

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to limited partner ownership interest (4)

  $ (98.0 )   $ (160.5 )   $ 62.8     $ 19.7     $ 64.0  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per limited partner unit (basic and diluted) (4)

  $ (2.17 )   $ (3.55 )   $ 1.39     $ 0.68     $ 2.40  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions paid per limited partner unit outstanding

  $ 1.43     $ 1.40     $ 1.14      
 

 

 

   

 

 

   

 

 

     

Financial Position Data (at year end): (2) (5)

         

Property, plant and equipment, net

  $ 4,114.5     $ 4,226.3     $ 4,159.7     $ 4,082.3     $ 3,963.0  

Total assets (6)

    4,916.0       5,272.1       5,752.1       6,033.6       5,667.4  

Long-term debt, excluding current maturities (6)

    818.5       888.2       758.0       332.2       —    

Partners’ capital:

         

Predecessor partner interest

    —         —         —         —         4,707.1  

Class A common units

    441.0       522.2       634.2       495.3       —    

Subordinated units

    980.8       1,062.0       1,174.0       1,035.1       —    

General Partner units

    49.3       43.3       47.8       42.2       —    

Accumulated other comprehensive income (loss)

    (0.4 )     (0.9 )     11.6       (3.1 )     7.1  

Noncontrolling interest

    2,299.1       2,405.7       2,529.0       2,983.2       —    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital

  $ 3,769.8     $ 4,032.3     $ 4,396.6     $ 4,552.7     $ 4,714.2  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    December 31,  
    2016     2015     2014     2013     2012 (1)  
    (in millions, except per unit amounts)  

Cash Flow Data: (2) (5)

         

Cash flows provided by operating activities

  $ 226.9     $ 207.0     $ 159.1     $ 420.9     $ 352.7  

Cash flows used in investing activities

  $ 37.1     $ 197.4     $ 231.3     $ 522.3     $ 614.5  

Cash flows provided by (used in) financing activities

  $ (200.4 )   $ 8.4     $ 67.3     $ 106.3     $ 261.8  

Additions to property, plant and equipment, acquisitions and investment in joint venture included in investing activities, net of cash acquired

  $ 67.3     $ 239.1     $ 274.6     $ 462.9     $ 621.1  

 

(1)  Represents the Predecessor historical information.
(2)  Our income statement, financial position and cash flow data reflect the following acquisitions and dispositions:

 

Date of Acquisition/Disposition

 

Description of Acquisition/Disposition

August 2016

  Disposition of trucks, trailers and related facilities

July 2015

  Disposition of propylene pipeline

July 2015

  Disposition of non-core Tinsley crude oil pipeline, storage facilities and docks

February 2015

  Acquisition of a Texas midstream business

 

(3)  Decreases in “Operating revenues” and “Commodity costs” for the years ended December 31, 2016 and 2015, as compared to prior years, are primarily due to decreases in commodity prices, the resulting decrease in volumes from reduced drilling activities, and Midcoast Operating subsidiaries’ direct sale of their natural gas products to third parties instead of through the Logistics and Marketing segment.
(4)  Represents calculation retrospectively reflecting the affiliate capitalization of MEP consisting of 4.1 million MEP Class A common units, 22.6 million MEP subordinated units and MEP general partner interest upon the transfer of a controlling ownership, including limited partner and general partner interest, in Midcoast Operating. The noncontrolling interest reflects the 61% that was retained by EEP through June 30, 2014. On July 1, 2014, we acquired an additional 12.6% interest in Midcoast Operating from EEP, decreasing EEP’s total ownership in Midcoast Operating to 48.4%.
(5)  Our financial position and cash flow data include the effect of the following public limited partner unit issuances:

 

Date of Unit Issuance

   Class of
Limited
Partnership
Interest
     Number of
Units Issued
     Net Proceeds
Including
General
Partner
Contribution
 
            (in millions)  

December 2013

     Class A        2,775,000      $ 47.0  

November 2013

     Class A        18,500,000      $ 304.5  

 

    The 2013 equity issuances represent the Offering.

 

(6)  Prior year amounts have been retrospectively adjusted upon adoption of ASU 2015-03, which requires presentation of debt issuance costs in the statement of financial position as a reduction to the carrying amount of Long-term debt, rather than as an asset. For further information, refer to Item 8. Financial Statements and Supplementary Data, Note 3. Changes in Accounting Policy.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

 

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MERGER OVERVIEW

On January 26, 2017, we entered into the merger agreement with EECI, an indirect subsidiary of Enbridge Inc., whereby EECI will acquire, for cash, all of our outstanding publicly held common units at a price of $8.00 per common unit for an aggregate transaction value of $170.2 million. The transaction is expected to close in the second quarter of 2017, subject to the satisfaction of customary conditions. Upon closing, we will cease to be a publicly traded partnership and will cease to be a reporting company under the SECs rules and regulations. The transaction will be a taxable event to our unaffiliated unitholders with recognition of gain or loss in the same manner as if they had sold their units in us for the transaction price. The transaction arises from the strategic alternatives review process, announced on May 2, 2016.

The closing of the merger is subject to customary conditions, including receipt of approval by a majority of our outstanding common units. As a result of the end of the subordination period, EEP’s subordinated units were converted to Class B common units on February 15, 2017. Thus, EEP currently holds approximately 52% of our outstanding common units, comprising the Class A common units and the Class B common units, which percentage will be sufficient for EEP to approve the Merger Agreement and the transactions contemplated thereby on behalf of the holders of our common units.

The Merger Agreement includes customary representations and warranties. It also includes customary covenants and agreements, including interim operating covenants and non-solicitation provisions. Prior to receipt of the requisite unitholder approval, the non-solicitation provisions are subject to an exception for unsolicited acquisition proposals that the board of directors of our General Partner, after consultation with the Conflicts Committee, determines are likely to result in a superior proposal. The Merger Agreement also includes customary termination provisions, including if the merger has not been completed by June 30, 2017.

In connection with the Merger, we, EECI and EEP also have entered into a Support Agreement, dated January 26, 2017, or the Support Agreement, pursuant to which EEP, in its capacity as a holder of units in us, has agreed to vote its units in favor of the Merger Agreement and the transactions contemplated by the Merger Agreement. The Support Agreement will terminate upon the earlier of (1) the effective time of the merger, (2) the date the Merger Agreement is terminated in accordance with its terms, (3) if the board of directors of EECI makes an adverse recommendation change as permitted by the terms of the Merger Agreement, or (4) on the date on which any modification, waiver or amendment to the Merger Agreement that is made without the prior written consent of EEP.

While the Merger is an initial step resulting from the strategic review process, EEP has indicated that it is continuing to explore and evaluate strategic alternatives with respect to its investment in us and Midcoast Operating.

RESULTS OF OPERATIONS — OVERVIEW

We are a growth-oriented Delaware limited partnership formed by EEP to serve as EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. Midcoast Operating is a Texas limited partnership that owns a network of natural gas and NGL gathering and transportation systems, natural gas processing and treating facilities and an NGL fractionation facility primarily located in Texas and Oklahoma. Midcoast Operating also owns and operates natural gas, NGL and condensate logistics and marketing assets that primarily support its gathering, processing and transportation business. Through our ownership of Midcoast Operating’s general partner, we control, manage and operate these systems.

We gather natural gas from the wellhead and central receipt points on our systems, deliver it to our facilities for processing and treating and redeliver the residue gas to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies. We deliver the NGLs produced at our processing plants to intrastate pipelines and interstate pipelines for transportation to the

 

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NGL market hubs in Mont Belvieu, Texas and Conway, Kansas. We also deliver a portion of NGLs produced at our fractionation facility at one of our processing plants to a wholesale customer. In addition, we provide marketing services of natural gas and NGLs to wholesale customers.

On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Logistics and Marketing segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third party. From that date through October 2016, Midcoast Operating subsidiaries sold their natural gas products directly to third parties, instead of through the Logistics and Marketing segment. The arrangement for Midcoast Operating subsidiaries to sell natural gas products directly to third parties expired on October 31, 2016. Since that date, Midcoast Operating subsidiaries have sold their natural gas products to third parties through the Logistics and Marketing segment.

Our financial condition and results of operations are subject to variability from multiple factors, including:

 

    the volumes of natural gas, NGLs, condensate, and crude oil that we gather, process and transport on our systems;

 

    the price of natural gas, NGLs, condensate, and crude oil that we pay for and receive in connection with the services we provide;

 

    our ability to replace or renew existing contracts; and

 

    the supply and demand for natural gas, NGLs, condensate, and crude oil.

We conduct our business through two distinct reporting segments: Gathering, Processing and Transportation and Logistics and Marketing. We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

The following table reflects our operating income by business segment and other charges for each of the periods presented:

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Operating income (loss)

        

Gathering, Processing and Transportation

   $ (131.2 )    $ (224.2 )    $ 114.9  

Logistics and Marketing

     (15.1 )      (53.6 )      43.5  

Other

     (6.3 )      (4.7 )      (5.7 )
  

 

 

    

 

 

    

 

 

 

Total operating income (loss)

     (152.6 )      (282.5 )      152.7  

Interest expense

     (33.3 )      (29.5 )      (16.7 )

Other income

     30.9        28.9        12.9  

Income tax expense

     (2.0 )      (1.4 )      (4.6 )
  

 

 

    

 

 

    

 

 

 

Net income (loss)

   $ (157.0 )    $ (284.5 )    $ 144.3  
  

 

 

    

 

 

    

 

 

 

Less: Net income (loss) attributable to noncontrolling interest

     (57.1 )      (120.6 )      80.2  
  

 

 

    

 

 

    

 

 

 

Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.

   $ (99.9 )    $ (163.9 )    $ 64.1  
  

 

 

    

 

 

    

 

 

 

Derivative Transactions and Hedging Activities

Contractual arrangements in our Gathering, Processing and Transportation segment and our Logistics and Marketing segment expose us to market risks associated with changes in commodity prices where we receive

 

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natural gas or NGLs in return for the services we provide or where we purchase natural gas or NGLs. Our unhedged commodity position is fully exposed to fluctuations in commodity prices, which can be significant during periods of price volatility. We use derivative financial instruments such as futures, forwards, swaps, options and other financial instruments with similar characteristics to manage the risks associated with market fluctuations in commodity prices, as well as to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. Derivative financial instruments that do not receive hedge accounting under the provisions of authoritative accounting guidance create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not receive hedge accounting in our consolidated statements of income as “Operating revenue” and “Commodity costs.”

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net changes in fair value associated with our derivative financial instruments:

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Gathering, Processing and Transportation segment:

        

Hedge ineffectiveness

   $ —        $ (4.1 )    $ 5.6  

Non-qualified hedges

     (108.5 )      (31.2 )      123.6  

Logistics and Marketing segment:

        

Non-qualified hedges

     (3.6 )      (23.0 )      29.2  
  

 

 

    

 

 

    

 

 

 

Derivative fair value net gains (losses)

   $ (112.1 )    $ (58.3 )    $ 158.4  
  

 

 

    

 

 

    

 

 

 

RESULTS OF OPERATIONS — BY SEGMENT

Gathering, Processing and Transportation

Our gathering, processing and transportation business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. Revenues for our gathering, processing and transportation business are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported and sold through our systems; the volumes of NGLs sold; and the level of natural gas, NGL and condensate prices. The segment gross margin of our gathering, processing and transportation business, which we define as revenue generated from gathering, processing and transportation operations less the commodity costs purchased, is derived from the compensation we receive from customers in the form of fees or commodities we receive for providing our services, in addition to the proceeds we receive for the sales of natural gas, NGLs and condensate to affiliates and third parties.

 

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The following tables set forth the operating results of our Gathering, Processing and Transportation segment and approximate average daily volumes of natural gas throughput and NGLs produced on our major systems for the periods presented:

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Operating revenues

   $ 738.5      $ 588.5      $ 647.3  

Commodity costs

     471.0        173.8        27.1  
  

 

 

    

 

 

    

 

 

 

Segment gross margin

     267.5        414.7        620.2  
  

 

 

    

 

 

    

 

 

 

Operating and maintenance

     194.6        216.0        260.6  

General and administrative

     55.4        67.3        87.1  

Goodwill impairment

     —          206.1        —    

Asset impairment

     —          —          15.6  

Depreciation and amortization

     148.7        149.5        142.0  
  

 

 

    

 

 

    

 

 

 

Operating expenses

     398.7        638.9        505.3  
  

 

 

    

 

 

    

 

 

 

Operating income (loss)

     (131.2 )      (224.2 )      114.9  

Other income

     30.0        29.3        12.9  
  

 

 

    

 

 

    

 

 

 

Net income (loss)

   $ (101.2 )    $ (194.9 )    $ 127.8  
  

 

 

    

 

 

    

 

 

 

Operating Statistics (MMBtu/d):

        

East Texas

     904,000        964,000        1,030,000  

Anadarko

     616,000        773,000        827,000  

North Texas

     197,000        265,000        293,000  
  

 

 

    

 

 

    

 

 

 

Total

     1,717,000        2,002,000        2,150,000  
  

 

 

    

 

 

    

 

 

 

NGL Production (Bpd)

     68,843        81,632        83,675  
  

 

 

    

 

 

    

 

 

 

Year ended December 31, 2016, compared with year ended December 31, 2015

The operating loss of our Gathering, Processing and Transportation segment for the year ended December 31, 2016, decreased $93.0 million, as compared with the year ended December 31, 2015, primarily due to the $206.1 million goodwill impairment charge recorded during 2015. No similar charge was recorded during the same period in 2016. The effects of the lack of impairment charge were offset by lower segment gross margin in the 2016 period, as discussed below.

Segment gross margin decreased $147.2 million for the year ended December 31, 2016, as compared with the year ended December 31, 2015, in part due to an increase of $73.2 million in non-cash, mark-to-market losses due to derivative transactions for the year ended December 31, 2016, as compared to the same period in 2015. These derivative losses are primarily related to the increased commodity prices of condensate and NGLs period over period, as well as losses from the reversal of previously recognized unrealized mark-to-market gains when the underlying transactions were settled.

Segment gross margin decreased $41.8 million for the year ended December 31, 2016, compared to the year ended December 31, 2015, due to reduced natural gas production volumes. The average daily volumes of our major systems for the year ended December 31, 2016 decreased by approximately 285,000 million British Thermal units per day, or MMBtu/d, or 14%, when compared to the year ended December 31, 2015. The average NGL production for the year ended December 31, 2016, decreased by 12,789 Bpd, or 16%, when compared to the year ended December 31, 2015. The decrease in volumes was primarily attributable to the extended low commodity price environment for natural gas and condensate, which resulted in reductions in drilling activity by producers in the areas we operate.

 

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Segment gross margin decreased $16.9 million for the year ended December 31, 2016, when compared to the same period in 2015, due to a decrease in processing margins primarily driven by lower NGL prices along with a decline in NGL volumes and associated keep whole volumes in the Anadarko and East Texas regions.

Segment gross margin also decreased $14.3 million for the year ended December 31, 2016, as compared with the year ended December 31, 2015, due to decreased margins from lower NGL prices, net of hedges, related to contracts where we were paid in commodities for our services.

Operating and maintenance and general and administrative costs together decreased $33.3 million for the year ended December 31, 2016, when compared to the year ended December 31, 2015, primarily due to continued cost reduction efforts, including decreases in operational, contract labor, workforce reductions and other cost reduction efforts. As part of our workforce reductions in 2016, we incurred severance costs of $1.8 million. Operating and administrative costs also decreased due to gains of $5.6 million recorded during the first quarter of 2016 to recognize return of escrow funds and a reversal of a contingent liability related to an acquisition. For further details regarding these amounts, refer to Item 1. Financial Statements, Note 6. Acquisitions.

Increases in “Operating revenues” and “Commodity costs” for the year ended December 31, 2016 are primarily due to increased natural gas sales directly to third parties instead of through the Logistics and Marketing segment. On October 31, 2016, upon the expiration of a third-party contract, the Gathering, Processing and Transportation segment resumed selling its natural gas through the Logistics and Marketing segment instead of directly to a third party.

Year ended December 31, 2015, compared with year ended December 31, 2014

The operating income of our Gathering, Processing and Transportation segment for the year ended December 31, 2015, decreased $339.1 million, as compared with the year ended December 31, 2014, primarily due to the $206.1 million goodwill impairment charge recorded during 2015, as well as lower segment gross margin, as discussed below.

Segment gross margin decreased $205.5 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, in part due to a decrease of $164.5 million from non-cash, mark-to-market losses of $35.3 million and gains of $129.2 million for the years ended December 31, 2015 and 2014, respectively. These losses are primarily related to the reclassification of previously recognized unrealized mark-to-market gains as the underlying transactions were settled, coupled with decreased non-cash, mark-to-market net gains due to smaller decreases in average forward prices during 2015 than in 2014.

Segment gross margin decreased $28.0 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to decreased margins from lower commodity prices, net of hedges, related to contracts where we were paid in commodities for our services.

Segment gross margin decreased $28.7 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, due to reduced natural gas production volumes. The average daily volumes of our major systems for the year ended December 31, 2015, decreased by approximately 148,000 million British Thermal units per day, or MMBtu/d, or 7% when compared to the year ended December 31, 2014. The average NGL production for the year ended December 31, 2015, decreased by 2,043 Bpd, or 2%, when compared to the year ended December 31, 2014. The decrease in natural gas and NGL volumes was primarily attributable to the extended low commodity price environment for natural gas, NGLs and condensate, which has resulted in reductions in drilling activity from producers in the areas we operate.

Segment gross margin increased $7.4 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to decreased physical measurement losses as a result of system efficiencies.

 

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Physical measurement gains and losses routinely occur on our systems as part of our normal operations, which result from evaporation, shrinkage, differences in measurement between receipt and delivery locations and other operational conditions.

Operating and maintenance and general and administrative costs together decreased $64.4 million for the year ended December 31, 2015, when compared to the year ended December 31, 2014, primarily due to cost reduction efforts undertaken by management, including $9.7 million in workforce reductions, which resulted in a decrease in contract labor as well as other related cost benefits.

Depreciation and amortization expense for our Gathering, Processing and Transportation segment increased $7.5 million, for the year ended December 31, 2015, compared with the year ended December 31, 2014, due to additional assets that were placed into service.

Other income increased $16.4 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, primarily due to increases in equity earnings on our investment in the Texas Express NGL system. These increases were a result of higher volumes and increases in ship-or-pay commitments during 2015.

Future Prospects Update for Gathering, Processing and Transportation

Demand for our midstream services primarily depends upon the supply of natural gas and associated natural gas from crude oil development and the drilling rate for new wells. Demand for these services depends on overall economic conditions and commodity prices. Commodity prices for natural gas, NGLs, condensate, and crude oil continue to remain low. The depressed commodity price environment is the most significant factor for reduced drilling activity and low volumes in the basins in which we operate. Due to the extended low commodity price environment, we expect drilling activity to remain low in the basins in which we operate, and as a result, we expect to see declining volumes on our systems in 2017.

We have a hedging program in place to assist in mitigating our direct commodity risk from contracts in which we are paid in commodities for our services. However, we are not fully hedged, and our hedge positions for 2017 are significantly lower than they were in 2016. We have hedged approximately 70% and 5% of our direct forecasted commodity cash flow exposure for 2017 and 2018, respectively. Our condensate and NGL hedge prices for 2017 are approximately 20% and on average 30% lower than 2016, respectively. See Liquidity and Capital Resources — Derivative Activities below. Despite our hedging program, we still bear indirect commodity price exposure as lower drilling activity impacts the volumes on our systems as well as direct commodity price exposure for unhedged commodity positions. We expect this indirect impact on our volumes to fluctuate depending on future price movements. In addition, we also expect our average NGL transportation commitments on the Texas Express system to increase from 29,000 Bpd in 2016 to 75,000 Bpd in 2017.

In light of the extended low commodity price environment and the ongoing challenges it presents to our business, we are working with EEP to explore and evaluate strategic alternatives in addition to, or as alternatives to, our long-term expansion strategies to address these challenges. EEP has also indicated that it is reviewing strategic alternatives with respect to its investment in us and Midcoast Operating. The additional various strategic alternatives may include, but are not necessarily limited to: asset sales; mergers, joint ventures, reorganizations or recapitalizations; and further reductions in operating and capital expenditures. The evaluation process is ongoing, and no decision on any particular strategic alternative has been reached.

Enbridge, our ultimate parent, recently announced a merger with Spectra Energy Corp. and has indicated that as part of the integration resulting from the Spectra merger, its existing U.S. sponsored vehicles, which includes us, will be reviewed in context of the combined enterprise. In addition, under the merger agreement between Enbridge and Spectra Energy Corp., Enbridge has agreed that it and its subsidiaries, including us, will conduct their businesses in the ordinary course prior to completing the merger transaction, subject to certain

 

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specified exceptions or the consent of Spectra Energy. Thus, while we and EEP continue to progress our strategic evaluation to address the challenges in our natural gas business, it is possible that the evaluation and potential execution of any such strategies could be affected by that merger and extend into the second quarter of 2017.

Logistics and Marketing

The primary role of our logistics and marketing business is to provide marketing services of natural gas, NGLs and condensate received from our gathering, processing and transportation business. We purchase and receive natural gas, NGLs and other products from pipeline systems and processing plants and sell and deliver them to wholesale customers, distributors, refiners, fractionators, chemical facilities, various third parties and end users. Our Logistics and Marketing segment derives a majority of its operating income from selling natural gas, NGLs and condensate received from producers on our Gathering, Processing and Transportation segment pipeline assets. A majority of the natural gas and NGLs we purchase are produced in Texas markets where we have expanded third-party pipeline deliverability alternatives over the past several years. We use our connectivity to interstate pipelines to improve value for producers by delivering natural gas into premium markets and NGLs to primary markets where we sell them to major customers. Additionally, our Logistics and Marketing segment derives operating income from providing logistics services for our customers from the wellhead to markets.

On August 15, 2016, we sold certain trucks, trailers and related facilities in our Logistics and Marketing segment and recognized a loss on disposal of $1.9 million for the year ended December 31, 2016. For further details, refer to Item 8. Financial Statements and Supplementary Data, under Note 10. Property, Plant and Equipment. Our Logistics and Marketing segment will contract with third parties to transport NGLs and condensate by truck.

On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Logistics and Marketing segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third party. From that date through October 2016, Midcoast Operating subsidiaries sold their natural gas products directly to third parties, instead of through the Logistics and Marketing segment, which has seen reduced activity related to the sale of natural gas products as a result. The arrangement for Midcoast Operating subsidiaries to sell natural gas products directly to third parties expired on October 31, 2016. Since that date, Midcoast Operating subsidiaries have resumed selling their natural gas products through the Logistics and Marketing segment instead of directly to third parties.

The following table sets forth the operating results of our Logistics and Marketing segment for the periods presented:

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Operating revenues

   $ 1,227.5      $ 2,254.2      $ 5,247.0  

Commodity costs

     1,188.1        2,199.1        5,118.8  
  

 

 

    

 

 

    

 

 

 

Segment gross margin

     39.4        55.1        128.2  
  

 

 

    

 

 

    

 

 

 

Operating and maintenance

     32.4        56.0        62.9  

General and administrative

     5.8        11.7        12.4  

Goodwill impairment

     —          20.4        —    

Asset impairment

     10.6        12.3        —    

Depreciation and amortization

     5.7        8.3        9.4  
  

 

 

    

 

 

    

 

 

 

Operating expenses

     54.5        108.7        84.7  
  

 

 

    

 

 

    

 

 

 

Operating income (loss)

   $ (15.1 )    $ (53.6 )    $ 43.5  
  

 

 

    

 

 

    

 

 

 

 

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Year ended December 31, 2016, compared with year ended December 31, 2015

The operating loss of our Logistics and Marketing segment for the year ended December 31, 2016, decreased $38.5 million, as compared with the year ended December 31, 2015, primarily as a result of a $20.4 million goodwill impairment charge that was recognized during the year ended December 31, 2015. No such goodwill impairment charge was recognized during 2016. In addition, combined operating and maintenance and general and administrative costs decreased, offset by decreased segment gross margin, as discussed below.

Decreases in “Operating revenues” and “Commodity costs” for the year ended December 31, 2016, as compared with the year ended December 31, 2015, are primarily due to decreases in commodity prices and the resulting decrease in volumes from reduced drilling activities, and Midcoast Operating subsidiaries’ direct sale of their natural gas products to third parties instead of through the Logistics and Marketing segment through October 31, 2016, as discussed above.

Segment gross margin decreased $15.7 million for the year ended December 31, 2016, as compared with the year ended December 31, 2015, primarily due to a decrease in storage margins of $34.0 million as a result of lower system volumes and the sale of liquids product inventory at lower prevailing market prices relative to the cost of product inventory.

Segment gross margin also decreased $12.7 million for the year ended December 31, 2016, as compared to the same period in 2015, related to dispositions and other transactions that occurred in 2015. In the third quarter of 2015, we sold our non-core Tinsley system and assigned certain storage agreements, transportation contracts and other arrangements to third parties. As a result, the segment margin generated by these assets for the year ended December 31, 2015 was not present in the same period of 2016.

Decreases in segment gross margin were offset by a net decrease in non-cash, mark-to-market losses due to derivative transactions of $19.4 million for the year ended December 31, 2016, as compared to the same period in 2015. These decreases in derivative losses are primarily related to gains from the reversal of previously recognized unrealized mark-to-market losses when the underlying transactions were settled, partially offset by losses from the increased commodity prices of NGLs period over period and $1.6 million of gains recognized in 2015 associated with the assignments of certain natural gas contracts.

Segment gross margin increased by $9.3 million for the year ended December 31, 2016, as compared to the same period in 2015, due to costs that were incurred associated with the sale of certain natural gas inventories, and assignment of certain storage agreements, transportation contracts and other arrangements to a third party in September 2015 that were not incurred during the same period in 2016.

Decreases in segment gross margin were also offset by an increase of $5.2 million for the year ended December 31, 2016, as compared with the year ended December 31, 2015, for decreases in non-cash charges to decrease the cost basis of our natural gas inventory to net realizable value recorded in 2015. No such charges were recognized in 2016.

Operating and maintenance and general and administrative costs combined decreased $29.5 million for the year ended December 31, 2016, as compared with the year ended December 31, 2015, primarily due to workforce reductions, decreases in repairs and maintenance, and other costs savings related to the sale of certain trucks, trailers and related facilities during third quarter of 2016 and other general cost reduction efforts.

Year ended December 31, 2015, compared with year ended December 31, 2014

The operating income of our Logistics and Marketing segment for the year ended December 31, 2015, decreased $97.1 million, as compared with the year ended December 31, 2014. Decreases in “Operating revenues” and “Commodity costs” for the year ended December 31, 2015, as compared with the year ended

 

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December 31, 2014, are primarily due to decreases in commodity prices and the resulting decreased volumes from lower drilling activities.

The most significant area affected was segment gross margin, which decreased $73.1 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014. In addition, for the year ended December 31, 2015, the Logistics and Marketing segment recognized a $20.4 million goodwill impairment charge and a non-cash impairment charge of $12.3 million from an expected loss on disposal of our non-core, held-for-sale assets. The goodwill impairment resulted from the impacts on our marketing business from sustained reductions in drilling activities in the areas in which our Gathering, Processing and Transportation segment operates.

Segment gross margin experienced a net decrease of $52.2 million including $1.6 million of gains associated with the assignments of certain natural gas contracts, due to non-cash, mark-to-market losses for the year ended December 31, 2015, as compared with the year ended December 31, 2014. These losses are primarily related to the reclassification of previously recognized unrealized mark-to-market gains as the underlying transactions were settled, coupled with decreased non-cash, mark-to-market net gains due to smaller decreases in average forward prices during 2015 than in 2014.

Our segment gross margin also decreased $9.3 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to costs associated with the sale of certain natural gas inventories, and assignment of certain storage agreements, transportation contracts and other arrangements to a third party.

Our segment gross margin was impacted by decreased margins within our gas marketing function due to natural gas pricing differentials between market centers by approximately $9.7 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014. During the first quarter of 2014, we benefited from the difference between market centers in the Mid-Continent supply areas and market centers in the Midwest which arose due to higher than usual demand from winter weather conditions in the Midwest.

Our segment gross margin decreased $8.0 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to lower storage margins as a result of the relative difference between the injection price paid to purchase and store natural gas, crude oil and NGLs and the withdrawal price at which these commodities are sold from storage.

Our segment gross margin increased $5.6 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, for decreases in non-cash charges to decrease the cost basis of our natural gas inventory to net realizable value recorded in 2014.

Operating and maintenance and general and administrative costs together decreased $7.6 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, primarily due to a decrease in outside contract labor as well as other related benefit costs due to workforce reductions in December 2014. In addition, other cost reduction efforts have resulted in reduced repairs and maintenance costs.

 

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Other

Other consists of interest expense and other costs such as income taxes, which are not allocated to the business segments.

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Operating and maintenance

   $ 0.4      $ 1.1      $ 0.4  

General and administrative

     5.9        3.6        5.3  
  

 

 

    

 

 

    

 

 

 

Operating expenses

     6.3        4.7        5.7  
  

 

 

    

 

 

    

 

 

 

Operating loss

     (6.3 )      (4.7 )      (5.7 )

Interest expense, net

     (33.3 )      (29.5 )      (16.7 )

Other income (loss)

     0.9        (0.4 )      —    
  

 

 

    

 

 

    

 

 

 

Loss before income tax expense

     (38.7 )      (34.6 )      (22.4 )

Income tax expense

     (2.0 )      (1.4 )      (4.6 )
  

 

 

    

 

 

    

 

 

 

Net loss

   $ (40.7 )    $ (36.0 )    $ (27.0 )
  

 

 

    

 

 

    

 

 

 

Year ended December 31, 2016, compared with year ended December 31, 2015

Net loss in other increased $4.7 million for the year ended December 31, 2016, as compared to the same period in 2015. The increase was primarily a result of an increase in interest expense of $3.8 million, due to lower capitalized interest and an increase in our average outstanding long-term debt balance and average interest rates on our Credit Agreement.

Year ended December 31, 2015, compared with year ended December 31, 2014

Net loss in other increased $9.0 million for the year ended December 31, 2015, as compared to the same period in 2014. The increase was a result of an increase in interest expense of $12.8 million, primarily due to a full year of interest expense incurred on our senior notes, which were issued in a private placement offering in September 2014. In addition, income tax expense decreased $3.2 million for the year ended December 31, 2015, as compared to the same period in 2014, primarily due to a $3.5 million tax benefit from a reduction in deferred income tax payable and from an overall lower franchise tax rate in 2015. This reduction is the result of a reduction in the Texas franchise tax rate from the Texas Franchise Tax Reduction Act of 2015. Offsetting the reduction in the Texas franchise tax for the year ended December 31, 2015 was an increase in deferred income tax expense of approximately $2.4 million incurred due to a higher Texas franchise tax apportionment factor.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary ongoing sources of liquidity include cash generated from operations of Midcoast Operating and borrowings under our senior revolving credit facility, which we refer to as the Credit Agreement. Depending on market conditions and other factors, we may also rely on issuances of additional debt and equity securities.

In light of the extended low commodity price environment and the ongoing challenges it presents to our business, we undertook a strategic alternatives review process to evaluate opportunities to strengthen our business. On January 26, 2017, we entered into the merger agreement with EECI, whereby EECI will acquire, for cash, all of our outstanding publicly held common units at a price of $8.00 per common unit for an aggregate transaction value of $170.2 million. For further details, refer to Part I, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations — Overview.

 

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Equity and Debt Financing Activities

Credit Agreement

We, Midcoast Operating, and our material subsidiaries are parties to the Credit Agreement, which permits aggregate borrowings of up to, at any one time outstanding, $670.0 million. The original term of the Credit Agreement was three years subject to four one-year requests for extensions at the lenders’ discretion, two of which we have utilized. Our Credit Agreement’s current maturity date is September 30, 2018; however, $25.0 million of commitments will expire on September 30, 2017.

At December 31, 2016, we had $420.0 million in outstanding borrowings under the Credit Agreement at a weighted average interest rate of 2.99%. Under the Credit Agreement, we had net repayments of approximately $70.0 million during the year ended December 31, 2016, which includes gross borrowings of $7,836.3 million and gross repayments of $7,906.3 million. For further details regarding the Credit Agreement and the amendments thereto, refer to Item 8. Financial Statements and Supplementary Data, under Note 16. Debt.

Our Credit Agreement requires compliance with two financial covenants. We are not permitted to allow our ratio of consolidated funded debt to pro forma earnings before interest, taxes, depreciation and amortization, or EBITDA, (the total leverage ratio), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00. These covenants could limit our ability to undertake additional debt financing.

The credit facility is unsecured, but security will be provided upon occurrence of any of the following: (1) for two consecutive quarters, the total leverage ratio as described above, exceeds 4.25 to 1.00, or 4.75 to 1.00 during acquisition periods, (2) uncured breach of certain terms and conditions of the Credit Agreement and (3) obtaining a non-investment grade initial debt rating from either S&P or Moody’s.

At December, 31, 2016, we were in compliance with the terms of our financial covenants in the Credit Agreement. Due to the extended low commodity price environment and the potential implications on our results of operations, it is likely that we may not meet the total leverage ratio financial covenant at some point during 2017 without further action on our part. If this were to occur, EEP has indicated to us that it expects to provide certain additional capital contributions to prevent a default under the Credit Agreement. We would also seek a waiver from our lenders, pursue refinancing of the amounts outstanding under the Credit Agreement, or seek to take other action to prevent a default under the Credit Agreement, although there can be no assurance that we will secure any such preventative actions. Failure to comply with one or both of the financial covenants may result in the occurrence of an event of default under the Credit Agreement, which would result in a cross-default under the note purchase agreement relating to our senior notes. If an event of default were to occur, the lenders could, among other things, terminate their commitments under the Credit Agreement, demand immediate payment of all amounts borrowed by us and Midcoast Operating, trigger the springing liens, and require adequate security or collateral for all outstanding letters of credit outstanding under the facility. In addition, we and Midcoast Operating are restricted under the Credit Agreement from making distributions if there is a continuing default under certain covenants, including the financial covenants. Any restrictions in our revolving credit facility could adversely affect our business, financial condition, and results of operations. See Item 1A. Risk Factors —Risks Related to Our Business.

 

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Available Liquidity

The following table sets forth liquidity sources at December 31, 2016:

 

     (in millions)  

Cash and cash equivalents

   $ 7.4  

Total commitments under Credit Agreement

   $ 670.0  

Amounts outstanding under Credit Agreement

   $ (420.0 )
  

 

 

 

Total

   $ 257.4  
  

 

 

 

The amounts we may borrow under the terms of our Credit Agreement are reduced by the face amount of our letters of credit outstanding.

As of December 31, 2016, we had a working capital deficit of approximately $161.2 million and approximately $257.4 million of liquidity (subject to Credit Agreement covenant compliance), as shown above, to meet our ongoing operational, investment and financing needs. For further details regarding our cash flow analysis, refer to Liquidity and Capital Resources — Cash Flow Analysis below.

Funding Arrangements with EEP

Distribution Support

During any quarter until the quarter ending December 31, 2017, if our quarterly declared distribution exceeds our distributable cash, as that term is defined in Midcoast Operating’s limited partnership agreement, we receive an increased quarterly distribution from Midcoast Operating, and EEP receives a corresponding reduction to its quarterly distribution in the amount that our declared distribution exceeds our distributable cash. Midcoast Operating’s adjustment of EEP’s distribution is limited by EEP’s pro rata share of the Midcoast Operating quarterly cash distribution and a maximum of $0.005 per unit quarterly distribution increase by us. There is no requirement for us to compensate EEP for these adjusted distributions, except for settling our capital accounts with Midcoast Operating in a liquidation scenario. For the year ended December 31, 2016, EEP’s distributions from Midcoast Operating were reduced by $15.9 million. For the year ended December 31, 2015, we did not receive an increased allocation of cash distributions from Midcoast Operating as distributable cash flow we generated exceeded the cash distribution amount we declared for payout.

To the extent we continue to have declared distributions each quarter at the current distribution level, we expect that EEP will continue to receive quarterly reductions in its distributions from Midcoast Operating throughout 2017. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in any amount. For more information refer to “Distributions” below.

Intercorporate Services Agreement

Under the Intercorporate Services Agreement, we entered into with EEP, or the Intercorporate Services Agreement, we reimburse EEP and its affiliates for the costs and expenses incurred in providing us with such various financial and business services, which are more fully described in Item 8. Financial Statements and Supplementary Data, under Note 23. Related Party Transactions — Intercorporate Services Agreement. EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually.

Financial Support Agreement

In addition, Midcoast Operating is party to a Financial Support Agreement with EEP, pursuant to which EEP provides letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time

 

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outstanding, in support of financial obligations of Midcoast Operating and its wholly owned subsidiaries under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. This agreement will terminate on November 13, 2017. At December 31, 2016, EEP provided no letters of credit and $39.9 million in guarantees. At December 31, 2015, EEP provided $7.5 million of letters of credit outstanding and $21.7 million in guarantees. Midcoast Operating incurs a 2.5% annual fee based on the cumulative average amount of letter of credit and guarantees outstanding under this agreement. Midcoast Operating incurred $0.5 million and $0.6 million of these costs at December 31, 2016 and 2015, respectively. For further details regarding the Financial Support Agreement, refer to Item 8. Financial Statements and Supplementary Data, under Note 23. Related Party Transactions.

Sale of Accounts Receivable

We and certain of our subsidiaries are parties to a receivables purchase arrangement, which we refer to as the Receivables Agreement, with an indirect wholly-owned subsidiary of Enbridge. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of participating sellers, consisting of certain of our subsidiaries and certain EEP subsidiaries up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected. The Receivables Agreement was amended in June 2016 to extend the termination date of the agreement to December 31, 2019.

During 2016, we sold and derecognized receivables to an indirect wholly-owned subsidiary of Enbridge for $1,713.0 million. As a result, we received cash proceeds of $1,712.2 million for the year ended December 31, 2016. As of December 31, 2016, outstanding receivables of $199.1 million, which had been sold and derecognized, had not been collected on behalf of the Enbridge subsidiary.

For further details regarding the Receivables Agreement, refer to Item 8. Financial Statements and Supplementary Data, under Note 23. Related Party Transactions.

Cash Requirements

Senior Notes

We have outstanding $400.0 million of notes consisting of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. We pay interest on all of the Notes semi-annually on March 31 and September 30, and commenced on March 31, 2015.

The Notes were issued pursuant to a Note Purchase Agreement, or the Purchase Agreement, between us and the purchasers named therein. The Notes and all other obligations under the Purchase Agreement are unconditionally guaranteed by each of our material subsidiaries pursuant to a guaranty agreement. Until such time as we obtain an investment grade rating from either Moody’s or S&P and upon certain trigger events, we and the guarantors will grant liens in our assets (subject to certain excluded assets) to secure the obligations under the Notes. There are currently no liens associated with the Notes.

The Purchase Agreement also requires compliance with two financial covenants. We must not permit the ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four-quarter period to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We also must maintain, on a consolidated basis, as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.

At December 31, 2016, we were in compliance with the terms of our financial covenants under the Notes and the related Purchase Agreement. Due to the extended low commodity price environment and the potential

 

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implications on our results of operations, it is likely that we may not meet the total leverage ratio financial covenant at some point during 2017 without further action on our part. If this were to occur, EEP has indicated to us that it expects to provide certain additional capital contributions to prevent a default under the Credit Agreement. We would also seek a waiver from the note holders, pursue refinancing of the amounts outstanding under the Notes, or seek to take other action to prevent a default under the Purchase Agreement and the Notes, although there can be no assurance that we will secure any such preventative actions. Any failure to comply with one or both of the financial covenants could result in an event of default under the Purchase Agreement and the Notes and result in a cross-default under the Credit Agreement. If an event of default were to occur, the note holders could, among other things, demand immediate payment of the Notes and trigger the springing liens. In addition, we and Midcoast Operating are restricted under the Credit Agreement from making distributions if there is a continuing default under certain covenants, including the financial covenants. Any restrictions in our revolving credit facility could adversely affect our business, financial condition, and results of operations.

For further details about the Notes and related private placement, refer to Item 8. Financial Statements and Supplementary Data, under Note 16. Debt.

Capital Spending

We categorize our capital expenditures as either maintenance or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which are worn, obsolete or completing their useful lives. Examples of maintenance capital expenditures include expenditures to replace pipelines or processing facilities, to maintain equipment reliability, integrity and safety or to comply with existing governmental regulations and industry standards. We also include in maintenance capital expenditures a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital expenditures will increase due to the growth of our pipeline systems. We expect to fund our proportionate share of maintenance capital expenditures through operating cash flows.

Expansion capital expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards. Examples of expansion capital expenditures include the acquisition of additional assets or businesses, as well as capital projects that improve the service, integrity and safety capability of our existing assets, increase operating capacities or revenues, reduce operating costs from existing levels, or enable us to comply with new governmental regulations or industry standards. We anticipate funding our proportionate share of expansion capital expenditures temporarily through borrowings under the Credit Agreement, with long-term debt and equity funding being obtained when needed and as market conditions allow.

Capital projects at Midcoast Operating are currently funded by us and by EEP based on our proportionate ownership percentages in Midcoast Operating, which are 51.6% and 48.4%, respectively. Under Midcoast Operating’s partnership agreement, we and EEP each have the option to contribute our proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund expansion capital expenditures or other growth projects. To the extent that we or EEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions to Midcoast Operating to the extent necessary to fully fund such expenditures in exchange for additional ownership interests in Midcoast Operating. For the year ended December 31, 2016, EEP provided approximately $10.9 million to fund its share of enhancement projects.

If EEP elects not to fund any capital expenditures at Midcoast Operating, we will have the option to fund all or a portion of EEP’s proportionate share of such capital expenditures in exchange for additional interests in

 

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Midcoast Operating. As a result, if our interests in Midcoast Operating increase, our proportionate share of the capital expenditures incurred by Midcoast Operating will also increase proportionate to our interest in Midcoast Operating. To the extent that EEP elects not to fund all or a portion of its proportionate share of Midcoast Operating’s capital expenditures, and we elect not to fund any capital expenditures not funded by EEP, we expect that Midcoast Operating will not pursue the applicable capital projects associated with such unfunded capital expenditures.

We incurred capital expenditures of $56.1 million for the year ended December 31, 2016, including $27.6 million of maintenance capital activities. At December 31, 2016, we had approximately $2.2 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment in the future.

Forecasted Expenditures

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. The following table sets forth Midcoast Operating’s estimated maintenance and expansion capital expenditures of $40.0 million, net of joint funding from EEP, for the year ending December 31, 2017. Although we anticipate making these expenditures in 2017, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets.

 

     Total
Forecasted
Expenditures
 
     (in millions)  

Capital Projects

  

Compression Capital

   $ 5  

Well-connect Expansion Capital

     10  

Expansion Capital

     20  

Maintenance Capital Expenditure Activities

     40  
  

 

 

 
     75  
  

 

 

 

Less: Joint Funding from:

  

EEP (1)

     35  
  

 

 

 
   $ 40  
  

 

 

 

 

(1)  Joint funding is based upon EEP’s current 48.4% ownership of Midcoast Operating.

Distributions

Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. For the year ended December 31, 2016, our annual cash distribution rate was $1.43 per unit. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our General Partner has considerable discretion to determine the amount of our available cash each quarter. In addition, our General Partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. For further discussion of risks related to our distribution, see Item 1A. Risk Factors — Risks Related to Our Business.

 

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Generally, our available cash is our (1) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (2) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

Subordinated Units

Our partnership agreement provides that, during the subordination period, the Class A common units had the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3125 per Class A common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the Class A common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units.

The subordination period began upon the closing of our initial public offering in November 2013 and ended on February 15, 2017. On that date, the outstanding subordinated units converted into a new class of common units, which we refer to as Class B common units, on a one-for-one basis, and all Class A common units are no longer entitled to arrearages. There were no arrearages during the subordination period.

Derivative Activities

The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at December 31, 2016 for each of the indicated calendar years:

 

     Notional (1)      2017     2018     2019      2020      2021 &
Thereafter
     Total (2)  
     (in millions)  

Swaps:

                  

Natural gas

     27,375,880      $ 4.7     $ —       $ —        $ —        $ —        $ 4.7  

NGL

     10,362,500        (6.1 )     —         —          —          —          (6.1 )

Crude Oil

     1,604,500        (1.2 )     —         —          —          —          (1.2 )

Options:

                  

NGL — puts purchased

     1,642,500        3.4       —         —          —          —          3.4  

NGL — calls written

     1,642,500        (13.4 )     —         —          —          —          (13.4 )

Crude Oil — puts purchased

     730,000        4.6       0.2       —          —          —          4.8  

Crude Oil — calls written

     730,000        (1.1 )     (0.8 )     —          —          —          (1.9 )

Forward contracts:

                  

Natural gas

     54,160,693        0.6       0.1       0.1        —          —          0.8  

NGL

     15,701,727        1.7       1.4       —          —          —          3.1  

Crude Oil

     453,392        (1.3 )     —         —          —          —          (1.3 )
     

 

 

   

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Totals

      $ (8.1 )   $ 0.9     $ 0.1      $ —        $ —        $ (7.1 )
     

 

 

   

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  Notional amounts for natural gas are recorded in MMBtu, whereas NGLs and crude oil are recorded in Bbl.
(2)  Fair values exclude credit valuation adjustments gains of approximately $0.1 million at December 31, 2016.

 

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Summary of Obligations and Commitments

The following table summarizes the principal amount of our obligations and commitments at December 31, 2016:

 

    2017     2018     2019     2020     2021     Thereafter     Total  
    (in millions)        

Scheduled maturities of debt obligations (1)

  $ —       $ 420.0     $ 75.0     $ —       $ 175.0     $ 150.0     $ 820.0  

Estimated cash payments for interest (2)

    16.3       16.3       16.5       13.7       13.7       19.9       96.4  

Purchase commitments (3)

    2.2       —         —         —         —         —         2.2  

Operating leases

    18.5       15.2       14.0       13.8       13.9       45.1       120.5  

Right-of-way

    0.5       0.4       0.3       0.6       0.1       —         1.9  

Product purchase obligations (4)

    132.4       83.4       69.9       71.3       71.1       201.6       629.7  

Transportation/Service contract obligations (5)

    115.3       125.7       129.6       125.3       124.7       213.4       834.0  

Fractionation agreement obligations (6)

    74.8       74.8       74.8       75.0       74.8       81.3       455.5  

Other long-term liabilities (7)

    0.2       0.2       0.2       0.2       0.2       0.4       1.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 360.2     $ 736.0     $ 380.3     $ 299.9     $ 473.5     $ 711.7     $ 2,961.6  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)  Represents scheduled future maturities of our consolidated debt principal obligations. For information regarding our consolidated debt obligations, see Item 8. Financial Statements and Supplementary Data, under Note 16. Debt.
(2)  Estimated cash payments for interest exclude adjustments for derivative agreements and cash payments for interest on variable-rate debt. We borrow and repay at varying amounts and interest rates. For more information on our debt obligations, see Item 8. Financial Statements and Supplementary Data, under Note 16. Debt.
(3)  Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects.
(4)  Represents long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at the approximate market value at the time of delivery.
(5)  Represents the minimum payment amounts for contracts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.
(6)  Represents the minimum payment amounts from contracts for firm fractionation of our NGL supply that we reserve at third party fractionation facilities.
(7)  Includes noncurrent portion of deferred credits. We are unable to estimate deferred income taxes (see Item 8. Financial Statements and Supplementary Data, under Note 21. Income Taxes ) since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. We are also unable to estimate asset retirement obligations (see Item 8. Financial Statements and Supplementary Data, under Note 17. Asset Retirement Obligations), environmental liabilities (see Item 8. Financial Statements and Supplementary Data, under Note 24. Commitments and Contingencies) and hedges payable (see Item 8. Financial Statements and Supplementary Data, under Note 20. Derivative Financial Instruments and Hedging Activities) due to the uncertainty as to the amount and, or, timing of when cash payments will be required.

 

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Cash Flow Analysis

The following table summarizes the changes in cash flows by operating, investing and financing for each of the years indicated:

 

     For the year ended
December 31,
 
     2016      2015      2014  
     (in millions)  

Total cash provided by (used in):

        

Operating activities

   $ 226.9      $ 207.0      $ 159.1  

Investing activities

     (37.1 )      (197.4 )      (231.3 )

Financing activities

     (200.4 )      8.4        67.3  
  

 

 

    

 

 

    

 

 

 

Net increase (decrease) in cash and cash equivalents

     (10.6 )      18.0        (4.9 )

Cash and cash equivalents at beginning of year

     18.0        —          4.9  
  

 

 

    

 

 

    

 

 

 

Cash and cash equivalents at end of period

   $ 7.4      $ 18.0      $ —    
  

 

 

    

 

 

    

 

 

 

Changes in our working capital accounts are shown in the following table and discussed below:

 

     For the year ended
December 31,
 
     2016      2015      2014  
     (in millions)  

Receivables, trade and other

   $ 4.8      $ 2.9      $ 33.2  

Due from General Partner and affiliates

     54.0        12.1        608.6  

Accrued receivables

     35.3        173.5        (47.4 )

Inventory

     3.6        43.8        (4.9 )

Current and long-term other assets

     (11.4 )      10.1        (23.9 )

Due to General Partner and affiliates

     14.1        29.6        (468.2 )

Accounts payable and other

     (23.4 )      (11.7 )      (21.2 )

Accrued purchases

     28.0        (231.4 )      (90.5 )

Interest payable

     (0.2 )      0.2        4.7  

Property and other taxes payable

     (1.2 )      (2.5 )      1.1  
  

 

 

    

 

 

    

 

 

 

Changes in operating assets and liabilities

   $ 103.6      $ 26.6      $ (8.5 )
  

 

 

    

 

 

    

 

 

 

Year ended December 31, 2016 compared with year ended December 31, 2015

Operating Activities

Net cash provided by our operating activities increased $19.9 million for the year ended December 31, 2016 compared with the year ended December 31, 2015. An increase of cash from net changes in operating assets and liabilities of $77.0 million was partially offset by decreased cash from net income after non-cash adjustments of $57.1 million. The decrease in cash from net income after non-cash adjustments was due primarily to reduced volumes on our systems, as described above under Results of Operations — by Segment. The increase from net changes in operating assets and liabilities was primarily the result of general timing differences for cash receipts and payments and includes:

 

    Net increased cash from accrued receivables and accrued purchases of $121.2 million primarily resulting from lower commodity prices and volumes during the year ended December 31, 2015, where the changes during the same period in 2016 were relatively flat; and

 

    Decreased cash from inventory of $40.2 million primarily due to decreases in the volumes and price of inventory sold, as compared with the prior year.

 

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Investing Activities

Net cash used in our investing activities during the year ended December 31, 2016, decreased by $160.3 million, compared with the year ended December 31, 2015, primarily due to decreased spending on acquisitions and capital projects of $167.9 million.

Financing Activities

Net cash provided by our financing activities decreased $208.8 million for the year ended December 31, 2016, as compared with the year ended December 31, 2015, primarily due to net repayments under the Credit Agreement of $70.0 million for the year ended December 31, 2016, as compared to net borrowings of $130.0 million under the Credit Agreement for the same period in 2015.

Year ended December 31, 2015 compared with year ended December 31, 2014

Operating Activities

Net cash provided by our operating activities increased $47.9 million for the year ended December 31, 2015 compared with the year ended December 31, 2014, primarily due to increased cash from net income after non-cash adjustments of $12.8 million and increased cash from net changes in operating assets and liabilities of $35.1 million. The increase from net changes in operating assets and liabilities was primarily the result of general timing differences for cash receipts and payments and includes:

 

    Net increased cash from accrued receivables and accrued purchases of $80.0 million primarily due to a decline in prices of natural gas and NGLs in 2015, which resulted in net collections of cash earlier in the year;

 

    Increased cash from inventory of $48.7 million primarily resulting from an overall reduction of natural gas and NGLs inventories as compared with the prior year; and

 

    Decreased cash from net balances due to and due from the General Partner and its affiliates of $98.7 million. At the beginning of 2014, cash management functions from EEP were transferred to us, and large affiliate balances with EEP from the cash management program were largely settled. No such transaction occurred during 2015.

Investing Activities

Net cash used in our investing activities during the year ended December 31, 2015, decreased by $33.9 million, compared with the year ended December 31, 2014, primarily due to:

 

    Decreased cash used for additions to property, plant and equipment of $46.6 million, primarily due to the completion of major projects, such as the Beckville Processing Plant;

 

    Changes in contributions to fund our joint venture investment and distributions in excess of earnings in the Texas Express NGL system. This resulted in a net decrease of cash used to fund our joint venture investment of $16.7 million, primarily due to higher capital spending on Texas Express in 2014 and higher distributions from Texas Express in 2015 resulting from higher volumes and demand charges; and

 

    Increased cash used for acquisition of assets of $43.6 million due to the purchase of a midstream business in February 2015, with no such acquisitions during 2014. For further details regarding this acquisition, see Item 8. Financial Statements and Supplementary Data, under Note 6. Acquisitions and Dispositions.

 

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Financing Activities

Net cash provided by our financing activities decreased $58.9 million for the year ended December 31, 2015, compared with the year ended December 31, 2014, primarily due to:

 

    Decreased cash provided by the issuance of debt of $398.1 million in 2014 with no similar activity during 2015;

 

    Decreased cash provided by contributions from noncontrolling interest of $102.1 million primarily due to EEP’s decreased ownership in Midcoast Operating;

 

    Decreased cash used for payments to EEP for acquiring a portion of its noncontrolling interest in Midcoast Operating in 2014 of $350.0 million with no similar activity in 2015; and

 

    Increased cash from net borrowings on our credit facility of $105.0 million.

OFF-BALANCE SHEET ARRANGEMENTS

We have no significant off-balance sheet arrangements.

CHANGES IN ACCOUNTING POLICY

Adoption of New Standards

Simplifying the Presentation of Debt Issuance Costs

Effective January 1, 2016, we adopted Accounting Standards Update, or ASU, No. 2015-03 on a retrospective basis which, as of December 31, 2015 resulted in a decrease in “Other assets, net” of $1.8 million and a corresponding decrease in long-term debt of $1.8 million. The new standard requires debt issuance costs related to a recognized debt liability to be presented in the consolidated statements of financial position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. ASU No. 2015-15 was adopted in conjunction with the above standard. ASU No. 2015-15 clarifies presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line of credit.

Amendments to the Consolidation Analysis

Effective January 1, 2016, we adopted ASU No. 2015-02 on a modified retrospective basis, which amended and clarified the guidance on variable interest entities, or VIEs. There was a significant change in the assessment of limited partnerships and other similar legal entities as VIEs, including the removal of the presumption that the general partner should consolidate a limited partnership. As a result, we have determined that certain entities that we historically consolidated are VIEs. The amended guidance did not impact our accounting treatment of such entities. However, material disclosures for VIEs have been provided, as necessary.

Future Accounting Policy Changes

Restricted Cash Presentation on Statement of Cash Flows

ASU No. 2016-18 was issued in November 2016 with the intent to add or clarify guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the cash flow statement. The amendments require that changes in restricted cash and restricted cash equivalents should be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017 and is to be applied on a retrospective basis.

 

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Recognition of Leases

ASU No. 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the consolidated statements of financial position and disclosing additional key information about leasing arrangements. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018, and is to be applied using a modified retrospective approach.

Recognition and Measurement of Financial Assets and Liabilities

ASU No. 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation, and disclosure of financial assets and liabilities. The amendments revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value, and the disclosure requirements associated with the fair value of financial instruments. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017, and is to be applied by means of a cumulative-effect adjustment to the statements of financial position as of the beginning of the fiscal year of adoption.

Revenues from Contracts with Customers

Since May 2014, ASU Nos. 2014-09, 2015-14, 2016-08, 2016-10 and 2016-12 were issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. We are currently assessing which transition method to use.

We reviewed a sample of our revenue contracts in order to evaluate the effect of the new standard on our revenue recognition practices. Based on our initial assessment, estimates of variable consideration which will be required under the new standard for certain contracts may result in changes to the pattern or timing of revenue recognition for those contracts. While we have not yet completed our assessment, we tentatively do not expect these changes to have a material impact on our consolidated net income (loss). We are also developing processes to generate the disclosures required under the new standard.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our selection and application of accounting policies is an important process that has developed as our business activities have evolved and as new accounting pronouncements have been issued. Accounting decisions generally involve an interpretation of existing accounting principles and the use of judgment in applying those principles to the specific circumstances existing in our business. We believe the proper implementation and consistent application of all applicable accounting principles is critical. However, not all situations we encounter are specifically addressed in the accounting literature. In such cases, we must use our best judgment to implement accounting policies that clearly and accurately present the substance of these situations. We accomplish this by analyzing similar situations and the accounting guidance governing them and consulting with experts about the appropriate interpretation and application of the accounting literature to these situations.

In addition to the above, certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures with

 

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respect to contingent assets and liabilities. The basis for our estimates is historical experience, consultation with experts and other sources we believe to be reliable. While we believe our estimates are appropriate, actual results can and often do differ from these estimates. Any effect on our business, financial position, results of operations and cash flows resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

For a summary of our significant accounting policies, refer to Item 8. Financial Statements and Supplementary Data, Note 2. Summary of Significant Accounting Policies. We believe our critical accounting policies discussed in the following paragraphs address the more significant judgments and estimates we use in the preparation of our consolidated financial statements. Each of these areas involves complex situations and a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that affect our consolidated financial statements. Our management has discussed the development and selection of the critical accounting policies and estimates related to the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent liabilities with the Audit, Finance & Risk Committee of Midcoast Holding’s board of directors.

Revenue Recognition and the Estimation of Revenues and Commodity Costs

We recognize revenue upon delivery of natural gas and NGLs to customers, when services have been rendered, pricing is determinable and collectability is reasonably assured. For our gathering, processing and transportation and logistics and marketing businesses, we must estimate our current month revenue and commodity costs to permit the timely preparation of our consolidated financial statements. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data prior to preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and commodity costs based on the best available volume and price data for natural gas and NGLs delivered and received, along with an adjustment of the prior month’s estimate to equal the prior month’s actual data. As a result, there is one month of estimated data recorded in our operating revenues and commodity costs for each period reported. We believe that the assumptions underlying these estimates will not be significantly different from the actual amounts due to the routine nature of these estimates and the consistency of our processes.

Derivative Financial Instruments

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, crude oil and related products in addition to fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows as they relate to inventories, firm commitments and certain anticipated transactions.

We record all derivative financial instruments at fair market value in our consolidated statements of financial position, which we adjust on a recurring basis each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the market approach, to value substantially all of our derivative instruments.

Price assumptions we use to value our non-qualifying derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from OTC market

 

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makers to find executable bids and offers. We may also use these inputs with internally developed methodologies that result in the best estimate of fair value. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs.

Depreciation

We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. Uncertainties that impact these assumptions include changes in laws and regulations that limit the estimated economic life of an asset, economic conditions and supply and demand in basins we serve. Based on the results of these assessments we may make modifications to the assumptions we use to determine our depreciation rates.

Asset Impairment

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Our intangible assets primarily consist of customer contracts for the purchase and sale of natural gas, natural gas supply opportunities and contributions we have made in aid of construction activities that will benefit our operations, as well as workforce contracts and customer relationships. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. If the total of the undiscounted future cash flows is less than the carrying amount of the property, plant and equipment or intangible assets, we write the assets down to fair value. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

We believe the assumptions used in evaluating recoverability of our assets are appropriate and result in reasonable estimates of the fair values of our assets. However, the assumptions used are subject to uncertainty, and declines in the future performance or cash flows of our assets, changes in business conditions, such as commodity prices and drilling, or increases to our weighted average cost of capital assumptions due to changes in credit or equity markets may result in the recognition of impairment charges, which could be significant.

 

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Commitments and Contingencies

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred. We believe these estimates are reasonable, however actual results could differ and it could result in material adjustments in results of operations between periods.

SUBSEQUENT EVENTS

Distribution to Partners

On January 26, 2017, the board of directors of Midcoast Holdings, acting in its capacity as the General Partner of MEP, declared a cash distribution payable to our unitholders on February 14, 2017. The distribution of our available cash of $16.5 million at December 31, 2016, or $0.3575 per limited partner unit was paid on February 14, 2017 to unitholders of record as of February 7, 2017. We paid $7.6 million to our public Class A common unitholders, while $8.9 million in the aggregate was paid to EEP with respect to its Class A common units and subordinated units and to Midcoast Holdings, with respect to its general partner interest.

Midcoast Operating Distribution

On January 26, 2017, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable on February 14, 2017 to its partners of record as of February 7, 2017. Midcoast Operating paid $27.9 million to us and $7.9 million to EEP.

Subordinated Units

The subordination period ended on February 15, 2017. On that date, the outstanding subordinated units converted into a new class of common units, which we refer to as Class B common units, on a one-for-one basis, and all Class A common units are no longer entitled to arrearages. For further details, refer to Item 8. Financial Statements and Supplementary Data, Note 18. Partner’s Capital — Subordinated Units.

Merger Agreement

On January 26, 2017, we entered into the merger agreement with EECI whereby EECI will acquire, for cash, all of our outstanding publicly held common units at a price of $8.00 per common unit for an aggregate transaction value of $170.2 million. For further details, refer to Item 8. Financial Statements and Supplementary Data, Note 1. Organization and Nature of Operations.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, crude oil and related products in addition to fractionation margins. Our exposure to commodity price risk exists within our Gathering, Processing and Transportation and Logistics and Marketing segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices as well as to reduce volatility to our cash flows. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments. Our portfolio of derivative financial instruments is largely comprised of natural gas, NGL and crude oil sales and purchase contracts. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an

 

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underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

The following transaction types do not receive hedge accounting and contribute to volatility in our earnings and in our cash flows upon settlement:

Commodity Price Exposures:

 

    Transportation — In our logistics and marketing business, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.

 

    Storage — In our logistics and marketing business, we use derivative financial instruments (i.e., natural gas, crude oil and NGL swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas, crude oil and NGLs and the withdrawal price at which these commodities are sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas, crude oil and NGLs injected and the price received upon withdrawal of these commodities from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of these commodities may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical commodities are recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical commodity is sold from storage. As a result, derivative financial instruments associated with our storage activities can increase volatility in our earnings due to fluctuations in commodity prices until the underlying transactions are settled or offset.

 

    Optional Natural Gas Processing Volumes — In our gathering, processing and transportation business, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

 

    NGL and Crude Oil Forward Contracts — In our logistics and marketing business, we use forward contracts to fix the price of NGLs and crude oil we purchase and sell to meet the demands of our customers that sell and purchase NGLs and crude oil. A subgroup of physical NGL and crude oil contracts qualify for the normal purchases and normal sales, or NPNS, scope exception. All other forward contracts are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL and crude oil prices until the forward contracts are settled.

 

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    Natural Gas Forward Contracts — In our logistics and marketing business, we use forward contracts to sell natural gas to our customers. A subgroup of our physical natural gas contracts qualify for the NPNS, scope exception. All other contracts are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.

 

    Condensate, Natural Gas and NGL Options — In our gathering, processing and transportation business, we use options to hedge the forecasted commodity exposure of our condensate, NGLs and natural gas. Although options can qualify for hedge accounting treatment, pursuant to the authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of condensate, NGLs and natural gas until the underlying transactions are settled.

In all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical cost or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at December 31, 2016 and 2015.

 

    At December 31, 2016     At December 31, 2015  
          Wtd. Average Price (2)     Fair Value     Fair Value (3)  
    Commodity     Notional (1)       Receive         Pay       Asset     Liability     Asset     Liability  
                      (in millions)        

Portion of contracts maturing in 2017

               

Swaps

               

Receive variable/pay fixed

    Natural Gas       5,145,880     $ 3.51     $ 3.00     $ 2.6     $ —       $ —       $ —    
    NGL       4,356,500     $ 29.43     $ 24.51     $ 21.4     $ —       $ —       $ (4.5 )
    Crude Oil       736,750     $ 56.00     $ 62.53     $ 0.9     $ (5.6 )   $ —       $ (10.9 )

Receive fixed/pay variable

    NGL       6,006,000     $ 25.74     $ 30.32     $ —       $ (27.5 )   $ 3.3     $ (0.1 )
    Crude Oil       867,750     $ 59.69     $ 55.69     $ 5.7     $ (2.2 )   $ 10.9     $ —    

Receive variable/pay variable

    Natural Gas       22,230,000     $ 3.59     $ 3.49     $ 2.5     $ (0.4 )   $ 0.5     $ (0.2 )

Physical Contracts

               

Receive variable/pay fixed

    Natural Gas       32,400     $ 3.68     $ 3.49     $ —       $ —       $ —       $ —    
    NGL       412,090     $ 23.61     $ 21.56     $ 0.9     $ —       $ —       $ —    

Receive fixed/pay variable

    Natural Gas       69,600     $ 3.56     $ 3.67     $ —       $ —       $ —       $ —    
    NGL       264,380     $ 33.22     $ 37.21     $ —       $ (1.2 )   $ —       $ —    

Receive variable/pay variable

    Natural Gas       49,299,457     $ 3.54     $ 3.52     $ 0.6     $ —       $ 0.1     $ —    
    NGL       8,269,007     $ 21.85     $ 21.61     $ 2.6     $ (0.6 )   $ —       $ —    
    Crude Oil       453,392     $ 50.34     $ 52.85     $ 0.7     $ (2.0 )   $ —       $ —    

Portion of contracts maturing in 2018

               

Physical Contracts

               

Receive variable/pay variable

    Natural Gas       2,193,804     $ 3.16     $ 3.13     $ 0.1     $ —       $ 0.1     $ —    
    NGL       6,756,250     $ 19.36     $ 19.15     $ 1.4     $ —       $ —       $ —    

Portion of contracts maturing in 2019

               

Physical Contracts

               

Receive variable/pay variable

    Natural Gas       2,199,798     $ 2.92     $ 2.90     $ 0.1     $ —       $ 0.1     $ —    

Portion of contracts maturing in 2020

               

Physical Contracts

               

Receive variable/pay variable

    Natural Gas       365,634     $ 3.13     $ 3.10     $ —       $ —       $ —       $ —    

 

(1)  Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)  Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.
(3)  The fair value is determined based on quoted market prices at December 31, 2016 and 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $0.6 million at December 31, 2015 as well as cash collateral received.

 

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The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at December 31, 2016 and 2015.

 

     At December 31, 2016     At December 31, 2015  
     Commodity    Notional (1)      Strike
Price (2)
     Market
Price (2)
     Fair Value (3)     Fair Value (3)  
                 Asset      Liability         Asset              Liability      
                 (in millions)  

Portion of option contracts maturing in 2017

 

                

Puts (purchased)

   NGL      1,642,500      $ 25.90      $ 35.05      $ 3.4      $ —       $ 5.8      $ —    
   Crude Oil      638,750      $ 59.86      $ 56.35      $ 4.6      $ —       $ 10.0      $ —    

Calls (written)

   NGL      1,642,500      $ 30.06      $ 35.05      $ —        $ (13.4 )   $ —        $ (0.8 )
   Crude Oil      638,750      $ 68.19      $ 56.35      $ —        $ (1.1 )   $ —        $ (0.6 )

Portion of option contracts maturing in 2018

 

                

Puts (purchased)

   Crude Oil      91,250      $ 42.00      $ 56.52      $ 0.2      $ —       $ —        $ —    

Calls (written)

   Crude Oil      91,250      $ 51.75      $ 56.52      $ —        $ (0.8 )   $ —        $ —    

 

(1)  Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)  Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
(3)  The fair value is determined based on quoted market prices at December 31, 2016 and 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude any credit valuation adjustment gains of approximately $0.1 million and losses of approximately $0.4 million at December 31, 2016 and 2015, respectively, as well as cash collateral received.

COUNTERPARTY CREDIT RISK

We are subject to the risk of loss resulting from the possibility that the counterparties, of our hedging contracts, may prove unable or unwilling to perform its obligations under the contracts, particularly during periods of weak and volatile economic conditions. The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so.

Our credit exposure for OTC derivatives is directly with our counterparty and continues until the maturity or termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and

 

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liquidity considerations. The table below summarizes our derivative balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty):

 

     December 31,  
     2016      2015  
     (in millions)  

Counterparty Credit Quality (1)

     

AA (2)

   $         2.5      $         67.6  

A

     (9.8 )      24.1  

Lower than A

     0.3        0.8  
  

 

 

    

 

 

 
   $ (7.0 )    $ 92.5  
  

 

 

    

 

 

 

 

(1)  As determined by nationally-recognized statistical ratings organizations.
(2)  Includes $12.6 million of cash collateral at December 31, 2015.

 

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Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS,

SUPPLEMENTARY INFORMATION AND

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

MIDCOAST ENERGY PARTNERS, L.P.

 

     Page  

Report of Independent Registered Public Accounting Firm

     D-89  

Consolidated Statements of Income for each of the years ended December 31, 2016, 2015 and 2014

     D-90  

Consolidated Statements of Comprehensive Income for each of the years ended December 31, 2016, 2015 and 2014

     D-91  

Consolidated Statements of Cash Flows for each of the years ended December 31, 2016, 2015 and 2014

     D-92  

Consolidated Statements of Financial Position as of December  31, 2016 and 2015

     D-93  

Consolidated Statements of Partners’ Capital for each of the years ended December 31, 2016, 2015 and 2014

     D-94  

Notes to the Consolidated Financial Statements

     D-95  

FINANCIAL STATEMENT SCHEDULES

Financial statement schedules not included in this report have been omitted because they are not applicable or the required information is either immaterial or shown in the consolidated financial statements or notes thereto.

 

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Report of Independent Registered Public Accounting Firm

To the Partners of Midcoast Energy Partners, L.P.:

In our opinion, the accompanying consolidated statements of financial position and the related consolidated statements of income, of comprehensive income, of partners’ capital and of cash flows present fairly, in all material respects, the financial position of Midcoast Energy Partners, L.P. and its subsidiaries (the “Partnership”) at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Partnership’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A of the Partnership’s 2016 Annual Report on Form 10-K. Our responsibility is to express opinions on these financial statements and on the Partnership’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 16, 2017

 

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MIDCOAST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

 

     For the year ended December 31,  
     2016     2015     2014  
     (in millions, except per unit amounts)  

Operating revenues:

      

Commodity sales (Note 20)

   $ 1,776.2     $ 2,573.4     $ 5,487.7  

Commodity sales — affiliate (Notes 20 and 23)

     9.4       73.0       206.1  

Transportation and other services

     180.4       196.3       200.5  
  

 

 

   

 

 

   

 

 

 
     1,966.0       2,842.7       5,894.3  
  

 

 

   

 

 

   

 

 

 

Operating expenses:

      

Commodity costs (Notes 8 and 20)

     1,621.3       2,295.1       5,026.7  

Commodity costs — affiliate (Notes 20 and 23)

     37.8       77.8       119.2  

Operating and maintenance

     140.5       172.9       219.2  

Operating and maintenance — affiliate (Note 23)

     86.9       100.2       104.7  

General and administrative

     8.0       7.2       8.7  

General and administrative — affiliate (Note 23)

     59.1       75.4       96.1  

Depreciation and amortization

     154.4       157.8       151.4  

Asset impairment (Note 10)

     10.6       12.3       15.6  

Goodwill impairment (Note 14)

     —         226.5       —    
  

 

 

   

 

 

   

 

 

 
     2,118.6       3,125.2       5,741.6  
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (152.6 )     (282.5 )     152.7  

Interest expense, net (Note 16)

     (33.3 )     (29.5 )     (16.7 )

Equity in earnings of joint ventures (Note 12)

     30.0       29.2       13.2  

Other income (loss)

     0.9       (0.3 )     (0.3 )
  

 

 

   

 

 

   

 

 

 

Income (loss) before income tax expense

     (155.0 )     (283.1 )     148.9  

Income tax expense (Note 21)

     (2.0 )     (1.4 )     (4.6 )
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (157.0 )   $ (284.5 )   $ 144.3  
  

 

 

   

 

 

   

 

 

 

Less: Net income (loss) attributable to noncontrolling interest

     (57.1 )     (120.6 )     80.2  
  

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.

   $ (99.9 )   $ (163.9 )   $ 64.1  
  

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to limited partner ownership interest

   $ (98.0 )   $ (160.5 )   $ 62.8  
  

 

 

   

 

 

   

 

 

 

Net income (loss) per limited partner unit (basic and diluted) (Note 4)

   $ (2.17 )   $ (3.55 )   $ 1.39  
  

 

 

   

 

 

   

 

 

 

Weighted average limited partner units outstanding

     45.2       45.2       45.2  
  

 

 

   

 

 

   

 

 

 

Cash distributions paid per limited partner unit outstanding

   $ 1.43     $ 1.40     $ 1.14  
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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MIDCOAST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     For the year ended
December 31,
 
     2016     2015     2014  
     (in millions)  

Net income (loss)

   $ (157.0 )   $ (284.5 )   $ 144.3  

Other comprehensive income (loss), net of tax (Note 20)

     (0.1 )     (24.3 )     30.4  
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

     (157.1 )     (308.8 )     174.7  

Less:

      

Net income (loss) attributable to noncontrolling interest

     (57.1 )     (120.6 )     80.2  

Other comprehensive income (loss) attributable to noncontrolling interest

     (0.6 )     (11.8 )     15.7  
  

 

 

   

 

 

   

 

 

 

Comprehensive income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.

   $ (99.4 )   $ (176.4 )   $ 78.8  
  

 

 

   

 

 

   

 

 

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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MIDCOAST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     For the year ended
December 31,
 
     2016     2015     2014  
     (in millions)  

Cash provided by operating activities:

      

Net income (loss)

   $ (157.0 )   $ (284.5 )   $ 144.3  

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

      

Depreciation and amortization

     154.4       157.8       151.4  

Derivative fair value net losses (gains) (Note 20)

     112.1       58.3       (158.4 )

Inventory market price adjustments (Note 8)

     —         5.8       11.4  

Asset impairment (Note 10)

     10.6       12.3       15.6  

Distributions from investment in joint ventures

     30.0       29.2       12.2  

Equity earnings from investment in joint ventures

     (30.0 )     (29.2 )     (13.2 )

Loss on sales of assets

     1.6       3.2       —    

Goodwill impairment (Note 14)

     —         226.5       —    

Other

     1.6       1.0       4.3  

Changes in operating assets and liabilities (Note 22)

     103.6       26.6       (8.5 )
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     226.9       207.0       159.1  
  

 

 

   

 

 

   

 

 

 

Cash used in investing activities:

      

Additions to property, plant and equipment (Note 22)

     (67.0 )     (191.1 )     (237.7 )

Changes in restricted cash (Note 7)

     6.6       28.2       18.7  

Acquisitions (Note 6)

     —         (43.8 )     (0.2 )

Proceeds from sales of assets

     13.6       2.5       —    

Investment in joint ventures

     (0.3 )     (4.2 )     (36.7 )

Distributions from investment in joint ventures in excess of cumulative earnings

     11.3       12.0       27.8  

Other

     (1.3 )     (1.0 )     (3.2 )
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (37.1 )     (197.4 )     (231.3 )
  

 

 

   

 

 

   

 

 

 

Cash provided by (used in) financing activities:

      

Proceeds from long-term debt, net of discounts (Note 16)

     —         —         398.1  

Net borrowings (repayments) under credit facility (Note 16)

     (70.0 )     130.0       25.0  

Acquisition of noncontrolling interest in subsidiary (Note 18)

     —         —         (350.0 )

Contributions from General Partner (Note 23)

     9.5       —         —    

Contributions from noncontrolling interest

     8.6       40.7       142.8  

Distributions to partners (Note 18)

     (66.0 )     (64.6 )     (52.7 )

Distributions to noncontrolling interest (Note 18)

     (82.5 )     (97.7 )     (95.9 )
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     (200.4 )     8.4       67.3  
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     (10.6 )     18.0       (4.9 )

Cash and cash equivalents at beginning of year

     18.0       —         4.9  
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 7.4     $ 18.0     $ —    
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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MIDCOAST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

     December 31,  
     2016     2015  
     (in millions)  

ASSETS

    

Current assets:

    

Cash and cash equivalents (Note 7)

   $ 7.4     $ 18.0  

Restricted cash (Note 7)

     11.0       20.6  

Receivables, trade and other, net of allowance for doubtful accounts of $2.4 million and $2.5 million in 2016 and 2015, respectively

     8.5       13.3  

Due from General Partner and affiliates (Note 23)

     4.2       47.0  

Accrued receivables

     20.8       56.1  

Inventory (Note 8)

     28.1       31.9  

Other current assets (Notes 9 and 20)

     60.7       118.5  
  

 

 

   

 

 

 
     140.7       305.4  

Property, plant and equipment, net (Note 10)

     4,114.5       4,226.3  

Equity investment in joint ventures (Note 12)

     360.7       372.3  

Intangible assets, net (Note 13)

     251.8       272.9  

Other assets, net (Note 20)

     48.3       95.2  
  

 

 

   

 

 

 

Total assets

   $ 4,916.0     $ 5,272.1  
  

 

 

   

 

 

 

LIABILITIES AND PARTNERS’ CAPITAL

    

Current liabilities:

    

Accounts payable and other (Notes 7, 15 and 20)

   $ 73.1     $ 92.6  

Due to General Partner and affiliates (Note 23)

     34.8       45.7  

Accrued purchases

     171.8       143.8  

Property and other taxes payable (Note 21)

     17.2       18.4  

Interest payable

     5.0       5.2  
  

 

 

   

 

 

 
     301.9       305.7  

Long-term debt (Note 16)

     818.5       888.2  

Other long-term liabilities (Notes 17, 20 and 21)

     25.8       45.9  
  

 

 

   

 

 

 

Total liabilities

     1,146.2       1,239.8  
  

 

 

   

 

 

 

Commitments and contingencies (Note 24)

    

Partners’ capital: (Note 18):

    

Class A common units (22,610,056 authorized and issued at December 31, 2016 and 2015)

     441.0       522.2  

Subordinated units (22,610,056 authorized and issued at December 31, 2016 and 2015)

     980.8       1,062.0  

General Partner units (922,859 authorized and issued at December 31, 2016 and 2015)

     49.3       43.3  

Accumulated other comprehensive loss (Note 20)

     (0.4 )     (0.9 )
  

 

 

   

 

 

 

Total Midcoast Energy Partners, L.P. partners’ capital

     1,470.7       1,626.6  

Noncontrolling interest

     2,299.1       2,405.7  
  

 

 

   

 

 

 

Total partners’ capital

     3,769.8       4,032.3  
  

 

 

   

 

 

 
   $ 4,916.0     $ 5,272.1  
  

 

 

   

 

 

 

Variable Interest Entities (VIEs) — see Note 11.

The accompanying notes are an integral part of these consolidated financial statements.

 

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MIDCOAST ENERGY PARTNERS’ L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

 

    For the year ended December 31,  
    2016     2015     2014  
    Units     Amount     Units     Amount     Units     Amount  
    (in millions, except unit amounts)  

Class A Common units:

           

Beginning balance

    22,610,056     $ 522.2       22,610,056     $ 634.2       22,610,056     $ 495.3  

Distributions to partners

    —         (32.3 )     —         (31.7 )     —         (25.8 )

Acquisition of noncontrolling interest in subsidiary

    —         —         —         —         —         133.3  

Net income (loss)

    —         (48.9 )     —         (80.3 )     —         31.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

    22,610,056       441.0       22,610,056       522.2       22,610,056       634.2  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Subordinated units:

           

Beginning balance

    22,610,056       1,062.0       22,610,056       1,174.0       22,610,056       1,035.1  

Distributions to partners

    —         (32.3 )     —         (31.7 )     —         (25.8 )

Acquisition of noncontrolling interest in subsidiary

    —         —         —         —         —         133.3  

Net income (loss)

    —         (48.9 )     —         (80.3 )     —         31.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

    22,610,056       980.8       22,610,056       1,062.0       22,610,056       1,174.0  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

General Partner:

           

Beginning balance

    922,859       43.3       922,859       47.8       922,859       42.2  

Contributions

    —         9.5       —         —         —         —    

Distributions to partners

    —         (1.4 )     —         (1.2 )     —         (1.1 )

Acquisition of noncontrolling interest in subsidiary

    —         —         —         —         —         5.4  

Net income (loss)

    —         (2.1 )     —         (3.3 )     —         1.3  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

    922,859       49.3       922,859       43.3       922,859       47.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Accumulated other comprehensive income (loss):

           

Beginning balance

      (0.9 )       11.6         (3.1 )

Changes in fair value of derivative financial instruments reclassified to earnings

      0.5         (17.0 )       1.8  

Changes in fair value of derivative financial instruments recognized in other comprehensive income

      —           4.5         12.9  
   

 

 

     

 

 

     

 

 

 

Ending balance

      (0.4 )       (0.9 )       11.6  
   

 

 

     

 

 

     

 

 

 

Total Midcoast Energy Partners, L.P. partners’ capital at December 31

      1,470.7         1,626.6         1,867.6  
   

 

 

     

 

 

     

 

 

 

Noncontrolling interest:

           

Beginning balance

      2,405.7         2,529.0         2,983.2  

Capital contributions

      33.6         106.8         167.8  

Acquisition of noncontrolling interest in subsidiary

      —           —           (622.0 )

Comprehensive income:

           

Net income (loss) allocation

      (57.1 )       (120.6 )       80.2  

Other comprehensive income (loss), net of tax

      (0.6 )       (11.8 )       15.7  

Distributions to noncontrolling interests

      (82.5 )       (97.7 )       (95.9 )
   

 

 

     

 

 

     

 

 

 

Ending balance

      2,299.1         2,405.7         2,529.0  
   

 

 

     

 

 

     

 

 

 

Total partners’ capital at December 31

    $ 3,769.8       $ 4,032.3       $ 4,396.6  
   

 

 

     

 

 

     

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND NATURE OF OPERATIONS

General

Midcoast Energy Partners, L.P. is a publicly-traded Delaware limited partnership formed by Enbridge Energy Partners, L.P., or EEP, to serve as EEP’s primary vehicle for owning and growing its natural gas and natural gas liquids midstream business in the United States. Midcoast Energy Partners, L.P., together with its consolidated subsidiaries, are referred to in this report as “we,” “us,” “our,” “MEP” and the “Partnership.” We own and operate, through our 51.6% controlling interest in Midcoast Operating, L.P., or Midcoast Operating, a portfolio of assets engaged in the business of gathering, processing and treating natural gas, as well as the transportation and marketing of natural gas, natural gas liquids, or NGLs, crude oil and condensate. Our portfolio of natural gas and NGL pipelines, plants and related facilities are geographically concentrated in the Gulf Coast and Mid-Continent regions of the United States, primarily in Texas and Oklahoma. We also own and operate natural gas and NGL logistics and marketing assets that primarily support our gathering, processing and transportation business. We hold our assets in a series of limited partnerships and limited liability companies that we wholly-own, either directly or indirectly. EEP owns a 48.4% noncontrolling interest in Midcoast Operating. EEP also has a significant interest in us through its ownership of our General Partner, which owns all of our General Partner units and all of our incentive distribution rights, or IDRs, as well as an approximate 52% limited partner interest in us. Our Class A common units trade on the New York Stock Exchange, or NYSE, under the ticker symbol “MEP.”

Merger Agreement

We and our general partner entered into the Merger Agreement pursuant to which EECI will acquire all of MEP’s outstanding Public Units. The holders of the Public Units will receive $8.00 in cash for each Public Unit for an aggregate transaction value of $170.2 million. The transaction is expected to close in the second quarter of 2017, subject to conditions described below. Upon closing, we will cease to be a publicly traded partnership and to file reports under the rules and regulations of the SEC. The transaction will be a taxable event to our unaffiliated unitholders with recognition of gain or loss in the same manner as if they had sold their units in us for the transaction price.

The closing of the merger is subject to customary conditions, including receipt of approval by a majority of our outstanding common units. As a result of the end of the subordination period, EEP’s subordinated units were converted to Class B common units on February 15, 2017. Thus, EEP currently holds approximately 52% of our outstanding common units, comprising the Class A common units and the Class B common units, which percentage will be sufficient for EEP to approve the Merger Agreement and the transactions contemplated thereby on behalf of the holders of our common units.

The Merger Agreement includes customary representations and warranties. It also includes customary covenants and agreements, including interim operating covenants and non-solicitation provisions. Prior to receipt of the requisite unit holder approval, the non-solicitation provisions are subject to an exception for unsolicited acquisition proposals that the board of directors, after consultation with the Conflicts Committee, determines are likely to result in a superior proposal. The Merger Agreement also includes customary termination provisions, including if the merger has not been completed by June 30, 2017.

In connection with the Merger, we, EECI and EEP also have entered into a Support Agreement, dated January 26, 2017, or the Support Agreement, pursuant to which EEP, in its capacity as a holder of units in us, has agreed to vote its units in favor of the Merger Agreement and the transactions contemplated by the Merger Agreement. The Support Agreement will terminate upon the earlier of (i) the effective time of the merger, (ii) the

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND NATURE OF OPERATIONS — (continued)

 

date the Merger Agreement is terminated in accordance with its terms, (iii) if the board of directors of EECI makes an adverse recommendation change as permitted by the terms of the Merger Agreement, or (iv) on the date on which any modification, waiver or amendment to the Merger Agreement that is made without the prior written consent of EEP.

Enbridge Energy Partners, L.P.

EEP was formed in 1991 by Enbridge Energy Company, Inc., its general partner, an indirect, wholly-owned subsidiary of Enbridge Inc., which we refer to as Enbridge. EEP was formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership, which owns the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada.

EEP is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets and, through its ownership interests in us, natural gas gathering, treating, processing, transmission and marketing assets in the United States of America. EEP’s Class A common units are traded on the New York Stock Exchange, or NYSE, under the symbol “EEP.”

Enbridge Energy Management, L.L.C.

Enbridge Energy Management, L.L.C., which we refer to as Enbridge Management, is a Delaware limited liability company that was formed by Enbridge Energy Company, Inc. in May 2002. EEP’s general partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management. Enbridge Management’s listed shares are traded on the NYSE under the symbol “EEQ.” Enbridge Management owns all of a special class of EEP’s limited partner interests and derives all of its earnings from its investment in EEP.

Enbridge Management’s principal activity is managing the business and affairs of EEP pursuant to a delegation of control agreement among EEP’s general partner, Enbridge Management and EEP. In accordance with its limited liability company agreement, Enbridge Management’s activities are restricted to being a limited partner of EEP and managing its business and affairs.

Enbridge Inc.

Enbridge is the indirect parent of EEP’s general partner, and its common shares are publicly traded on the NYSE in the United States and on the TSX in Canada, in each case, under the symbol “ENB.” Enbridge is headquartered in Calgary, Alberta, Canada, and is a leader in energy transportation and distribution in North America, with a focus on crude oil and liquids pipelines, natural gas pipelines, natural gas distribution and renewable energy. At December 31, 2016 and 2015, Enbridge and its consolidated subsidiaries held an effective 22.5% and 22.7% interest in MEP, respectively, through its indirect ownership in Enbridge Management and EEP’s general partner.

Business Segments

We conduct our business through two distinct reporting segments: Gathering, Processing and Transportation and Logistics and Marketing.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND NATURE OF OPERATIONS — (continued)

 

Gathering, Processing and Transportation

Our gathering, processing and transportation business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers, and an NGL fractionation facility. We gather natural gas from the wellhead and central receipt points on our systems, deliver it to our facilities for processing and treating and deliver the residue gas to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies. We deliver the NGLs produced at our processing and fractionation facilities to intrastate and interstate pipelines for transportation to the NGL market hubs in Mont Belvieu, Texas and Conway, Kansas.

Our gathering, processing and transportation business primarily consists of our Anadarko system, the East Texas system and the North Texas system, which provide natural gas gathering, processing, transportation and related services predominantly in producing basins in east and north Texas, as well as the Texas Panhandle and western Oklahoma. At December 31, 2016, our gathering, processing and transportation business included four active and six standby natural gas treating plants and 15 active and 10 standby natural gas processing plants, excluding plants that are inactive based on current volumes. In addition, our gathering, processing and transportation business includes approximately 10,800 miles of natural gas gathering and transmission pipelines and approximately 282 miles of NGL gathering and transportation pipelines.

We have a 35% aggregate interest in the Texas Express NGL system, which consists of two separate joint ventures with third parties that own and operate an NGL pipeline, or mainline, and NGL gathering system. The Texas Express NGL pipeline originates near Skellytown, Texas in the Texas Panhandle and extends approximately 593 miles to NGL fractionation and storage facilities in the Mont Belvieu area on the Texas Gulf Coast. The mainline has an initial capacity of approximately 280,000 Bpd and is expandable to approximately 400,000 Bpd with additional pump stations on the system. There are currently capacity reservations on the mainline that, when fully phased in, will total approximately 250,000 Bpd. In addition, the Texas Express NGL system consists of approximately 116 miles of gathering pipelines.

Logistics and Marketing

The primary role of our logistics and marketing business is to provide marketing services of natural gas, NGLs and condensate received from our gathering, processing and transportation business, thereby enhancing our competitive position. In addition, our logistics and marketing services provide our customers with the opportunity to receive enhanced economics by providing access to premium markets through the transportation capacity and other assets we control. Our logistics and marketing business purchases and receives natural gas, NGLs and other products from pipeline systems and processing plants and sells and delivers them to wholesale customers, distributors, refiners, fractionators, utilities, chemical facilities and power plants. Our logistics and marketing business related to natural gas saw reduced activity during 2016, as the majority of our natural gas was sold directly to third parties by our gathering, processing and transportation business. However, during the fourth quarter of 2016, our gathering, processing and transportation business resumed selling natural gas to the logistics and marketing business for sale to third parties.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Use of Estimates

We prepare our consolidated financial statements in accordance with generally accepted accounting principles in the United States of America, or U.S. GAAP. The preparation of these consolidated financial

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingent assets and liabilities. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known.

Principles of Consolidation

The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. Where we conclude we are the primary beneficiary of a VIE, we consolidate the accounts of that entity.

We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE.

All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method.

Revenue Recognition and the Estimation of Revenues and Commodity Costs

We recognize revenue upon delivery of natural gas and NGLs to customers, when services have been rendered, pricing is determinable and collectability is reasonably assured.

Gathering, Processing and Transportation

We derive revenue in our Gathering, Processing and Transportation business from the following types of arrangements:

Fee-Based Arrangements

In a fee-based arrangement, we receive a fee per thousand cubic feet, or Mcf, of natural gas processed or per gallon of NGLs produced. Under this arrangement, we have no direct commodity price exposure. Within our gathering, processing and transportation business, we receive fee-based revenue for services, such as compression fees, gathering fees and treating fees, which are recognized when services are performed. Additionally, revenues of our gathering, processing and transportation business that are derived from transmission services consist of reservation fees charged for transportation of natural gas on some of our intrastate pipeline systems. Customers paying these fees sometimes pay a reservation fee each month to reserve capacity plus a nominal commodity charge based on actual transportation volumes. Reservation fees are required

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

to be paid whether or not the shipper delivers the volumes, thus referred to as a ship-or-pay arrangement. Consequently, we recognize revenue for reservation fees ratably over the period in which capacity is reserved. Additional revenues from our intrastate pipelines are derived from the combined sales of natural gas and transportation services.

Commodity-Based Arrangements

We also generate revenue and segment gross margin under other types of service arrangements with customers. These arrangements expose us to commodity price risk, which we mitigate to a substantial degree with the use of derivative financial instruments to hedge open positions in these commodities. We hedge a significant amount of our exposure to commodity price risk to support the stability of our cash flows.

The commodity-based service contracts we have with customers are categorized as follows:

 

    Percentage-of-Proceeds Contracts — Under these contracts, we receive a negotiated percentage of the sales proceeds related to natural gas and NGLs we process. The processed products include residue natural gas, NGLs, condensate and sulfur, which we can sell at market prices and retain a percentage of the proceeds as our compensation. This type of arrangement exposes us to commodity price risk, as the revenues from percentage-of-proceeds contracts directly correlate with the market prices of the applicable commodities that we receive.

 

    Percentage-of-Liquids Contracts — Under these contracts, we receive a negotiated percentage of the NGLs extracted from natural gas that require processing, which we can then sell at market prices and retain the proceeds as our compensation. This contract structure is similar to percentage-of-proceeds arrangements except that we only receive a percentage of the NGLs produced. Ownership of the residue natural gas remaining after the extraction of NGLs resides with the customer. This type of contract may also require us to provide the customer with a guaranteed NGL recovery percentage regardless of actual NGL production. Since revenues from percentage-of-liquids contracts directly correlate with the market price of NGLs, this type of arrangement also exposes us to commodity price risk.

 

    Percentage-of-Index Contracts — Under these contracts, we purchase raw natural gas at a negotiated percentage of an agreed upon index price. We then resell the natural gas, generally for the index price, and keep the difference as our compensation.

 

    Keep-Whole Contracts — Under these contracts, we gather or purchase raw natural gas from the customer.

We extract and retain the NGLs produced during processing for our own account, which we then sell at market prices. In instances where we purchase raw natural gas at the wellhead, we may also sell the resulting residue natural gas for our own account at market prices. In those instances when we gather and process raw natural gas for the customer’s account, we generally must return to the customer residue natural gas with an energy content equivalent to the original raw natural gas we received, as measured in British thermal units, or Btu. This type of arrangement has the highest commodity price exposure because our costs are dependent on the price of natural gas purchased and our revenues are dependent on the price of NGLs sold. As a result, we benefit from these types of contracts when the value of NGLs is high relative to the cost of natural gas and are disadvantaged when the cost of natural gas is high relative to the value of NGLs.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

Under the terms of each of our commodity-based service contracts, we retain natural gas and NGLs as our compensation for providing these customers with our services. Our forecasted commodity cash flows for 2017 are hedged approximately 70%. Due to this unhedged commodity price exposure, our segment gross margin, representing revenue less commodity costs, generally increases when the prices of these commodities are rising and generally decreases when the prices are declining. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell the residue gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate.

Logistics and Marketing

Our logistics and marketing business derives a majority of its segment gross margin from purchasing and receiving natural gas, NGLs and other products from our gathering, processing and transportation business and from third-party pipeline systems and processing plants and selling and delivering them to wholesale customers, distributors, refiners, fractionators, utilities, chemical facilities and power plants. We contract for third-party pipeline capacity under firm and interruptible transportation contracts for which the pipeline capacity depends on volumes of natural gas from our natural gas assets, which provides us with access to several third-party interstate and intrastate pipelines that can be used to improve value for the producers by transporting natural gas to premium markets and NGLs to primary market hubs where they can be sold to major customers for these products. Our logistics and marketing business also uses owned and leased railcars to transport products such as NGLs, condensate and other liquid hydrocarbons to market. In some instances, our margin per unit of volume sold can be higher if the commodity being marketed requires specialized handling, treating, stabilization or other services.

Our logistics and marketing business also derives segment gross margin from the relative difference in natural gas and NGL prices between the contracted index at which the natural gas and NGLs are purchased and the index price at which they are sold, otherwise known as the “basis spread,” which can vary over time or by location, as well as due to local supply and demand factors. Natural gas and NGLs purchased and sold by our logistics and marketing business is primarily priced at a published daily or monthly price index. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated margins result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. We enter into long-term, fixed-price purchase or sales contracts with our customers and generally will enter into offsetting hedge positions under the same or similar terms.

Estimation of Revenue and Commodity Costs

In order to permit the timely preparation of our consolidated financial statements, we must estimate our current month revenue and commodity costs. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data before our preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and commodity costs based on the best available volume and price data for natural gas and natural gas liquids delivered and received, along with an adjustment of the prior month’s estimate to equal the prior month’s actual data. As a result, there is one month of estimated data recorded in our operating revenues and commodity costs for each of the years ended December 31, 2016, 2015 and 2014. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the consistency of our processes.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

Derivative Financial Instruments

We may use derivative financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows as they relate to inventories, firm commitments and certain anticipated transactions. We record all derivative financial instruments at fair market value in our consolidated statements of financial position.

Qualified Hedges

We may use cash flow hedges to manage our exposure to changes in commodity prices. To qualify for cash flow hedge accounting treatment, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation. At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective, and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of Midcoast Holdings or a committee of senior management appointed by our General Partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction and we do not use derivative financial instruments for speculative purposes.

The effective portion of the change in fair value of a cash flow hedge is recorded in other comprehensive income (loss) and is reclassified into earnings when the hedge item impacts earnings. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two month period of time thereafter. Although we retain the ability to designate commodity hedges for cash flow hedge accounting, as of December 31, 2016, we have no remaining commodity hedges designated as cash flow hedges.

Non-Qualified Hedges

We have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value included in “Commodity sales” or “Commodity costs” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

occurs. Although we retain the ability to designate commodity hedges for cash flow accounting, as of December 31, 2016, we have no remaining commodity hedges that are designated. As such, all commodity hedges are marked-to-market with the changes in fair value recorded in earnings each period.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value to our derivative instruments and disclosures associated with our outstanding commodity activities. Fair value is defined as the expected price we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

 

    Level 1 — We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments.

 

    Level 2 — We include in this category the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument. This category includes both OTC transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted prices for assets and liabilities; (b) time value; (c) volatility factors; and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

 

    Level 3 — We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: non-binding broker quotes, time value, volatility, correlation and extrapolation methods.

We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust on a recurring basis each period for changes in the fair market value, and refer to as marking to

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the “market approach,” to value substantially all of our derivative instruments.

Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities.

Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. Actively traded external market quotes, data from pricing services and published indices are also used to value our derivative instruments. We may use these inputs along with internally developed methodologies that result in our best estimates of fair value.

Income Taxes

We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of franchise tax laws by the State of Texas that apply to entities organized as partnerships. This tax is computed on our modified gross margin and we have determined the tax to be an income tax as set forth in authoritative accounting literature.

We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax liabilities and assets in the period the legislation is enacted.

We recognize the tax effects of any uncertain tax positions as the largest amount that will more likely than not be realized upon ultimate settlement with a taxing authority having full knowledge of the position and all relevant facts. We recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized.

Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.

Cash and Cash Equivalents

Cash equivalents are defined as all highly marketable securities with original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we

 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

have issued check payments that have not been presented to the financial institution are included in “Accounts payable and other” on our consolidated statements of financial position.

Restricted Cash

Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as “Restricted cash” on our consolidated statements of financial position.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.

Inventory

Inventory includes product inventory and materials and supplies inventory. We record all product inventories at the lower of our cost, as determined on a weighted average basis, or market value. Our product inventory consists of natural gas and liquid hydrocarbons, such as NGLs and condensate. Upon disposition, product inventory is recorded to “Commodity Costs” at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

Materials and supplies inventory is used either during operations and charged to “Operating and maintenance” as incurred, or for capital projects and new construction, and capitalized to “Property, plant and equipment, net.”

Operational Balancing Agreements and Natural Gas Imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through the receipt or delivery of natural gas in the future. Natural gas imbalances are recorded as “Accrued receivables” or “Accrued purchases” on our consolidated statements of financial position using the posted index prices, which approximate market rates, or our weighted average cost of natural gas.

Property, Plant and Equipment

We record property, plant and equipment at historical cost. We capitalize expenditures in excess of a minimum rule, which have a useful life greater than one year for: (1) assets purchased or constructed; (2) existing assets that are replaced, improved or the useful lives have been extended; or (3) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred. Expenditures for project development are capitalized if they are expected to have a future benefit. During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

We depreciate property, plant and equipment on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the natural gas production in the basins the assets serve. Upon disposition of distinct assets, we recognize any gains or losses in our consolidated statements of income. For largely homogeneous groups of assets with comparable useful lives, we record depreciation using the group method of depreciation whereby similar assets are grouped and depreciated as a group. Under this method, when group assets are retired or otherwise disposed of, gains and losses are not reflected in our consolidated statements of income but are recorded as an adjustment to accumulated depreciation.

Intangible Assets

Our intangible assets primarily consist of natural gas supply opportunities, customer contracts, and other intangible assets that will benefit our operations, such as software and contributions in aid of construction. We amortize these assets on a straight-line basis over the weighted average useful lives of the underlying assets, representing the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

Impairment

We evaluate the recoverability of our long-lived assets when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. If the carrying amount of the asset exceeds the sum of the undiscounted future cash flows, we recognize an impairment loss in the amount of the excess carrying amount of the asset over its fair value.

Asset Retirement Obligations

Legal obligations exist for a minority of our right-of-way agreements due to requirements or landowner options that compel us to remove the pipe at final abandonment. Sufficient data exists with certain pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions, or the estimated economic life of the asset. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to allow us to reasonably estimate potential settlement dates and methods.

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — (continued)

 

Commitments and Contingencies

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

3. CHANGES IN ACCOUNTING POLICY

Adoption of New Standards

Simplifying the Presentation of Debt Issuance Costs

Effective January 1, 2016, we adopted Accounting Standards Update, or ASU, No. 2015-03 on a retrospective basis which, as of December 31, 2015 resulted in a decrease in “Other assets, net” of $1.8 million and a corresponding decrease in long-term debt of $1.8 million. The new standard requires debt issuance costs related to a recognized debt liability to be presented in the consolidated statements of financial position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. ASU No. 2015-15 was adopted in conjunction with the above standard. ASU No. 2015-15 clarifies presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line of credit.

Amendments to the Consolidation Analysis

Effective January 1, 2016, we adopted ASU No. 2015-02 on a modified retrospective basis, which amended and clarified the guidance on variable interest entities, or VIEs. There was a significant change in the assessment of limited partnerships and other similar legal entities as VIEs, including the removal of the presumption that the general partner should consolidate a limited partnership. As a result, we have determined that certain entities that we historically consolidated are VIEs. The amended guidance did not impact our accounting treatment of such entities. However, material disclosures for VIEs have been provided, as necessary.

Future Accounting Policy Changes

Restricted Cash Presentation on Statement of Cash Flows

ASU No. 2016-18 was issued in November 2016 with the intent to add or clarify guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the cash flow statement. The amendments require that changes in restricted cash and restricted cash equivalents should be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017 and is to be applied on a retrospective basis.

Recognition of Leases

ASU No. 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the consolidated statements of financial

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

3. CHANGES IN ACCOUNTING POLICY — (continued)

 

position and disclosing additional key information about leasing arrangements. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018, and is to be applied using a modified retrospective approach.

Recognition and Measurement of Financial Assets and Liabilities

ASU No. 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation, and disclosure of financial assets and liabilities. The amendments revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value, and the disclosure requirements associated with the fair value of financial instruments. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017, and is to be applied by means of a cumulative-effect adjustment to the statements of financial position as of the beginning of the fiscal year of adoption.

Revenues from Contracts with Customers

Since May 2014, ASU Nos. 2014-09, 2015-14, 2016-08, 2016-10 and 2016-12 were issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. We are currently assessing which transition method to use.

We reviewed a sample of our revenue contracts in order to evaluate the effect of the new standard on our revenue recognition practices. Based on our initial assessment, estimates of variable consideration which will be required under the new standard for certain contracts may result in changes to the pattern or timing of revenue recognition for those contracts. While we have not yet completed our assessment, we tentatively do not expect these changes to have a material impact on our consolidated net income (loss). We are also developing processes to generate the disclosures required under the new standard.

4. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

We allocate our net income among our General Partner and limited partners using the two-class method. Under the two-class method, we allocate our net income, including any earnings in excess of distributions, to our limited partners, our General Partner and the holders of our IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and our

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

4. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST — (continued)

 

limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement.

 

Distribution Targets

   Portion of Quarterly
Distribution Per Unit
   Percentage
Distributed
to Limited Partners
    Percentage
Distributed
to General Partner
 

Minimum Quarterly Distribution

   Up to $0.3125      98 %     2 %

First Target Distribution

   > $0.3125 to $0.359375      98 %     2 %

Second Target Distribution

   > $0.359375 to
$0.390625
     85 %     15 %

Third Target Distribution

   > $0.390625 to
$0.468750
     75 %     25 %

Over Third Target Distribution

   In excess of $0.468750      50 %     50 %

We determined basic and diluted net income (loss) per limited partner unit as follows:

 

     For the year ended December 31,  
           2016                  2015                  2014        
     (in millions, except per unit amounts)  

Net income (loss)

   $ (157.0 )    $ (284.5 )    $ 144.3  

Less: Net income (loss) attributable to noncontrolling interest

     (57.1 )      (120.6 )      80.2  
  

 

 

    

 

 

    

 

 

 

Net income (loss) attributable to general and limited partner interests in Midcoast Energy Partners, L.P.

     (99.9 )      (163.9 )      64.1  

Less distributions:

        

Total distributed earnings to our General Partner

     1.4        1.2        1.2  

Total distributed earnings to our limited partners

     64.6        64.1        59.6  
  

 

 

    

 

 

    

 

 

 

Total distributed earnings

     66.0        65.3        60.8  
  

 

 

    

 

 

    

 

 

 

Underdistributed (Overdistributed) earnings

   $ (165.9 )    $ (229.2 )    $ 3.3  
  

 

 

    

 

 

    

 

 

 

Weighted average limited partner units outstanding

     45.2        45.2        45.2  
  

 

 

    

 

 

    

 

 

 

Basic and diluted earnings per unit:

        

Distributed earnings per limited partner unit (1)

   $ 1.43      $ 1.42      $ 1.32  

Underdistributed (Overdistributed) earnings per limited partner unit (2)

     (3.60 )      (4.97 )      0.07  
  

 

 

    

 

 

    

 

 

 

Net income (loss) per limited partner unit (basic and diluted)

   $ (2.17 )    $ (3.55 )    $ 1.39  
  

 

 

    

 

 

    

 

 

 

 

(1)  Represents the total distributed earnings to limited partners divided by the weighted average number of limited partner interests outstanding for the period.
(2)  Represents the limited partners’ share (98%) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and underdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

5. SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.

Each of our reportable segments is a business unit that offers different services and products that are managed separately, since each business segment requires different operating strategies. We conduct our business through two distinct reporting segments:

 

    Gathering, Processing, and Transportation; and

 

    Logistics and Marketing.

The following tables present certain financial information relating to our business segments and other activities. Interest expense, allowance for equity used during construction, income tax expense, noncontrolling interest, and certain other costs are not allocated to the business segments. These items are presented in “Other” in the table below:

 

    As of and for the year ended December 31, 2016  
    Gathering,
Processing and
Transportation
    Logistics and
Marketing
    Other     Total  
    (in millions)  

Total revenue

  $ 1,128.2     $ 1,247.0     $ —       $ 2,375.2  

Less: Intersegment revenue

    389.7       19.5       —         409.2  
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating revenue

    738.5       1,227.5       —         1,966.0  

Commodity costs

    471.0       1,188.1       —         1,659.1  
 

 

 

   

 

 

   

 

 

   

 

 

 

Segment gross margin

    267.5       39.4       —         306.9  
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating and maintenance

    194.6       32.4       0.4       227.4  

General and administrative

    55.4       5.8       5.9       67.1  

Depreciation and amortization

    148.7       5.7       —         154.4  

Asset impairment

    —         10.6       —         10.6  
 

 

 

   

 

 

   

 

 

   

 

 

 
    398.7       54.5       6.3       459.5  
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating loss

    (131.2     (15.1 )     (6.3 )     (152.6 )

Other income (expense)

    30.0  (1)      —         0.9       30.9  

Interest expense, net

    —         —         (33.3 )     (33.3 )
 

 

 

   

 

 

   

 

 

   

 

 

 

Loss before income tax expense

    (101.2     (15.1 )     (38.7 )     (155.0 )

Income tax expense

    —         —         (2.0 )     (2.0 )
 

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

    (101.2     (15.1 )     (40.7 )     (157.0 )

Less: Net loss attributable to noncontrolling interest

    —         —         (57.1 )     (57.1 )
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.

  $ (101.2   $ (15.1 )   $ 16.4     $ (99.9 )
 

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

  $ 4,716.6  (2)    $ 142.6     $ 56.8     $ 4,916.0  
 

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures (excluding acquisitions)

  $ 51.6     $ 2.6     $ 1.9     $ 56.1  
 

 

 

   

 

 

   

 

 

   

 

 

 

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

5. SEGMENT INFORMATION — (continued)

 

(1)  Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
(2)  Total assets for our Gathering, Processing and Transportation segment includes $360.7 million for our equity investment in the Texas Express NGL system.

 

     As of and for the year ended December 31, 2015  
     Gathering,
Processing and
Transportation
    Logistics and
Marketing
     Other      Total  
     (in millions)  

Total revenue

   $ 1,445.1     $ 2,290.5      $ —        $ 3,735.6  

Less: Intersegment revenue

     856.6       36.3        —          892.9  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating revenue

     588.5       2,254.2        —          2,842.7  

Commodity costs

     173.8       2,199.1        —          2,372.9  
  

 

 

   

 

 

    

 

 

    

 

 

 

Segment gross margin

     414.7       55.1        —          469.8  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating and maintenance

     216.0       56.0        1.1        273.1  

General and administrative

     67.3       11.7        3.6        82.6  

Depreciation and amortization

     149.5       8.3        —          157.8  

Asset impairment

     —         12.3        —          12.3  

Goodwill impairment

     206.1       20.4        —          226.5  
  

 

 

   

 

 

    

 

 

    

 

 

 
     638.9       108.7        4.7        752.3  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating loss

     (224.2     (53.6 )      (4.7 )      (282.5 )

Other income (expense)

     29.3  (1)      —          (0.4 )      28.9  

Interest expense, net

     —         —          (29.5 )      (29.5 )
  

 

 

   

 

 

    

 

 

    

 

 

 

Loss before income tax expense

     (194.9     (53.6 )      (34.6 )      (283.1 )

Income tax expense

     —         —          (1.4 )      (1.4 )
  

 

 

   

 

 

    

 

 

    

 

 

 

Net loss

     (194.9     (53.6 )      (36.0 )      (284.5 )

Less: Net loss attributable to noncontrolling interest

     —         —          (120.6 )      (120.6 )
  

 

 

   

 

 

    

 

 

    

 

 

 

Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.

   $ (194.9   $ (53.6 )    $ 84.6      $ (163.9 )
  

 

 

   

 

 

    

 

 

    

 

 

 

Total assets

   $ 5,004.6  (2)    $ 182.6      $ 84.9      $ 5,272.1  
  

 

 

   

 

 

    

 

 

    

 

 

 

Capital expenditures (excluding acquisitions)

   $ 162.3     $ 11.3      $ 4.9      $ 178.5  
  

 

 

   

 

 

    

 

 

    

 

 

 

 

(1)  Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
(2)  Total assets for our Gathering, Processing and Transportation segment includes $372.3 million for our equity investment in the Texas Express NGL system.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

5. SEGMENT INFORMATION — (continued)

 

     As of and for the year ended December 31, 2014  
     Gathering,
Processing and
Transportation
    Logistics and
Marketing
     Other      Total  
     (in millions)  

Total revenue

   $ 2,611.2     $ 5,329.8      $ —        $ 7,941.0  

Less: Intersegment revenue

     1,963.9       82.8        —          2,046.7  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating revenue

     647.3       5,247.0        —          5,894.3  

Commodity costs

     27.1       5,118.8        —          5,145.9  
  

 

 

   

 

 

    

 

 

    

 

 

 

Segment gross margin

     620.2       128.2        —          748.4  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating and maintenance

     260.6       62.9        0.4        323.9  

General and administrative

     87.1       12.4        5.3        104.8  

Depreciation and amortization

     142.0       9.4        —          151.4  

Asset impairment

     15.6       —          —          15.6  
  

 

 

   

 

 

    

 

 

    

 

 

 
     505.3       84.7        5.7        595.7  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating income (loss)

     114.9       43.5        (5.7 )      152.7  

Other income

     12.9  (1)      —          —          12.9  

Interest expense, net

     —         —          (16.7 )      (16.7 )
  

 

 

   

 

 

    

 

 

    

 

 

 

Income (loss) before income tax expense

     127.8       43.5        (22.4 )      148.9  

Income tax expense

     —         —          (4.6 )      (4.6 )
  

 

 

   

 

 

    

 

 

    

 

 

 

Net income (loss)

     127.8       43.5        (27.0 )      144.3  

Less: Net income attributable to noncontrolling interest

     —         —          80.2        80.2  
  

 

 

   

 

 

    

 

 

    

 

 

 

Net income (loss) attributable to general and limited partner ownership interests in Midcoast Energy Partners, L.P.

   $ 127.8     $ 43.5      $ (107.2 )    $ 64.1  
  

 

 

   

 

 

    

 

 

    

 

 

 

Total assets

   $ 5,205.4  (2)    $ 460.3      $ 86.4      $ 5,752.1  
  

 

 

   

 

 

    

 

 

    

 

 

 

Capital expenditures (excluding acquisitions)

   $ 213.4     $ 16.6      $ 6.0      $ 236.0  
  

 

 

   

 

 

    

 

 

    

 

 

 

 

(1)  Other income for our Gathering, Processing and Transportation segment includes our equity investment in the Texas Express NGL system.
(2)  Total assets for our Gathering, Processing and Transportation segment includes $380.6 million for our equity investment in the Texas Express NGL system.

Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. Our two largest non-affiliated customers accounted for approximately 21.2% and 10.1% of our third-party revenues for the year ended 2016. Our largest non-affiliated customer accounted for approximately 12.0% of our third-party revenues for the year ended December 31, 2015. No other customers accounted for 10% or more of our third-party revenues during any of the three years ended December 31, 2016, 2015, and 2014.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

6. ACQUISITIONS AND DISPOSITIONS

On February 27, 2015, we acquired a midstream business, which consisted of a natural gas gathering system in Leon, Madison and Grimes Counties, Texas. We acquired the midstream business for $85.0 million in cash and a contingent future payment of up to $17.0 million. Funding for the acquisition was provided by us and EEP, based on our proportionate ownership percentages in Midcoast Operating, at the time of acquisition, which was 51.6% and 48.4%, respectively. EEP paid its portion of the funding directly. Our consolidated statements of cash flows does not reflect the amount paid directly by EEP.

Of the $85.0 million purchase price, $20.0 million was placed into escrow, pending the resolution of a legal matter and completion and connection of additional wells to our system by February 2016. Since the acquisition date, we released $17.0 million from escrow for additional wells connected to our system and for the resolution of the legal matter. During the first quarter of 2016, $3.0 million in escrow was returned to us, as some of the additional wells were not connected to our system by February 2016. As a result, we recognized a $3.0 million gain as a reduction to “Operating and maintenance” expense, which is reflected in our consolidated statements of income for the year ended December 31, 2016. At December 31, 2016, no amounts remained in escrow. At December 31, 2015, “Restricted cash” and “Other assets, net” included $6.0 million and $6.0 million amounts in escrow, respectively, in our consolidated statements of financial position.

The purchase and sale agreement contained a provision whereby we would have been obligated to make future tiered payments of up to $17.0 million if volumes were delivered into the system at certain tiered volume levels over a five-year period. We determined at the time of the acquisition that the potential payment was contingent consideration. At the acquisition date, the fair value of this contingent consideration, using a probability-weighted discounted cash flow model was $2.3 million. The contingent consideration was re-measured on a fair value basis each quarter until December 31, 2015, which resulted in an addition to the liability of $0.3 million for accretion. During the first quarter of 2016, and in subsequent reassessments, we determined, based on current and forecasted volumes, that it is remote that we will be obligated to make any payments at the expiration of the five-year period. Consequently, we reversed the liability and recognized a $2.6 million gain as a reduction to “Operating and maintenance” expense, which is reflected in our consolidated statements of income for the year ended December 31, 2016.

The following table summarizes our final purchase price allocation for the acquisition:

 

     December 31,
2015
 
     (in millions)  

Consideration:

  

Cash consideration

   $ 85.0  

Contingent consideration

     2.3  
  

 

 

 
   $ 87.3  
  

 

 

 

Identifiable assets acquired in business combination:

  

Property, plant and equipment

   $ 55.1  

Intangible assets

     32.2  
  

 

 

 
   $ 87.3  
  

 

 

 

The weighted-average amortization period of intangible assets related to this acquisition is 15 years. Our consolidated operating revenue and net income included $3.5 million and $0.2 million, respectively, from this acquisition for the year ended December 31, 2015.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

6. ACQUISITIONS AND DISPOSITIONS — (continued)

 

Since the effective date of the acquisition was February 27, 2015, our consolidated statements of income do not include earnings from this business prior to that date. The following table presents selected unaudited pro forma earnings information for the year ended December 31, 2015 as if the acquisition had been completed on January 1, 2014. This pro forma information was prepared using historical financial data for the midstream business and reflects certain estimates and assumptions made by our management based on available information. Our unaudited pro forma financial information is not necessarily indicative of what our consolidated financial results would have been for the year ended December 31, 2015 had we acquired the midstream business on January 1, 2014.

 

     For the year ended
December 31,
 
     2015      2014  
     (in millions, except per
unit amounts)
 

Pro forma earnings data:

     

Operating revenue

   $ 2,842.8      $ 5,895.2  

Operating expenses

   $ 3,125.6      $ 5,743.7  

Operating income (loss)

   $ (282.8 )    $ 151.5  

Net income (loss)

   $ (284.8 )    $ 143.1  

Net income (loss) attributable to noncontrolling interest

   $ (120.7 )    $ 79.6  

Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.

   $ (164.1 )    $ 63.5  

Net income (loss) attributable to limited partner ownership interest

   $ (160.7 )    $ 62.4  

Basic and diluted earnings per unit:

     

As reported net income (loss) per limited partner unit (basic and diluted)

   $ (3.55 )    $ 1.39  

Pro forma net income (loss) per limited partner unit (basic and diluted)

   $ (3.55 )    $ 1.38  

Dispositions

On August 15, 2016, we sold certain trucks, trailers and related facilities in our Logistics and Marketing segment. Also, on July 31, 2015, we sold our non-core Tinsley crude oil pipeline, storage facilities, and docks in our Logistics and Marketing segment and our non-core Louisiana propylene in our Gathering, Processing and Transportation segment. For further details regarding these dispositions, refer to Note 10. Property, Plant and Equipment.

On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Logistics and Marketing segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third party. From that date through October 2016, Midcoast Operating subsidiaries sold their natural gas products directly to third parties, instead of through the Logistics and Marketing segment. The arrangement for Midcoast Operating subsidiaries to sell natural gas products directly to third parties expired on October 31, 2016. Since that date, Midcoast Operating subsidiaries have sold their natural gas products to third parties through the Logistics and Marketing segment.

During the year ended December 31, 2015, we received net proceeds of $4.3 million and recognized a loss of $9.3 million included in our “Segment gross margin,” which includes losses to transfer certain fixed-demand

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

6. ACQUISITIONS AND DISPOSITIONS — (continued)

 

storage and transportation obligations to the buyer. The proceeds included a prepayment of $4.2 million, which represents compensation for us to deliver natural gas to the buyer over an 11-month period commencing on September 1, 2015. For the years ended December 31, 2016, and 2015, we recognized $3.0 million and $1.2 million, respectively, as operating revenue, which are included in “Commodity sales” in our consolidated statements of income related to this prepayment. In addition, during the year ended December 31, 2015, we recognized $1.3 million in severance costs associated with the transaction, which is included in “Operating and maintenance” expense on our consolidated statement of income.

7. CASH AND CASH EQUIVALENTS

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have made payments that have not yet been presented to the financial institution, totaling approximately $4.5 million and $4.2 million at December 31, 2016 and 2015, respectively, are included in “Accounts payable and other” on our consolidated statements of financial position.

Restricted Cash

Restricted cash is comprised of the following:

 

     December 31,  
     2016      2015  
     (in millions)  

Cash collected on behalf of Enbridge subsidiary for accounts receivable sales and not yet remitted to the Enbridge subsidiary (see Note 23)

   $ 11.0      $ 14.6  

Cash held in escrow for acquisitions (see Note 6)

     —          6.0  
  

 

 

    

 

 

 
   $ 11.0      $ 20.6  
  

 

 

    

 

 

 

8. INVENTORY

Our inventory is comprised of the following:

 

     December 31,  
     2016      2015  
     (in millions)  

Materials and supplies

   $ 0.3      $ 0.6  

Natural gas and NGL inventory

     27.8        31.3  
  

 

 

    

 

 

 

Total inventory

   $ 28.1      $ 31.9  
  

 

 

    

 

 

 

“Commodity costs” on our consolidated statements of income include charges totaling $5.8 million and $11.4 million for the years ended 2015 and 2014, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs, to reflect the current market value. For the year ended December 31, 2016, we did not have any similar material charges related to our inventory of natural gas and NGLs.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

9. OTHER CURRENT ASSETS

Other current assets are comprised of the following:

 

     December 31,  
     2016      2015  
     (in millions)  

Short term portion of derivative assets (see Note 20)

   $ 44.1      $ 117.3  

Prepaid expenses and other

     16.6        1.2  
  

 

 

    

 

 

 

Total other current assets

   $ 60.7      $ 118.5  
  

 

 

    

 

 

 

10. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment is comprised of the following:

 

     December 31,  
     2016      2015  
     (in millions)  

Land

   $ 24.4      $ 14.2  

Rights-of-way

     458.9        460.3  

Pipelines

     1,877.9        1,864.4  

Pumping equipment, buildings and tanks

     87.5        88.4  

Compressors, meters and other operating equipment

     2,182.6        2,147.6  

Vehicles, office furniture and equipment

     86.3        137.1  

Processing and treating plants

     630.0        627.8  

Construction in progress

     32.3        57.1  
  

 

 

    

 

 

 

Total property, plant and equipment

     5,379.9        5,396.9  

Accumulated depreciation

     (1,265.4 )      (1,170.6 )
  

 

 

    

 

 

 

Property, plant and equipment, net

   $ 4,114.5      $ 4,226.3  
  

 

 

    

 

 

 

Depreciation expense for the years ended December 31, 2016, 2015, and 2014 was $130.9 million, $135.1 million and $139.1 million, respectively.

On August 15, 2016, we sold certain trucks, trailers and related facilities in our Logistics and Marketing segment for $12.1 million. At the date of sale, the assets had a total carrying amount of $14.0 million. The loss on disposal of $1.9 million for the year ended December 31, 2016 is included in “Operating and maintenance” expense on our consolidated statement of income.

On July 31, 2015, we sold our non-core Tinsley crude oil pipeline, storage facilities, and docks in our Logistics and Marketing segment and our non-core Louisiana propylene pipeline in our Gathering, Processing and Transportation segment. The sales price was $1.3 million, and the assets had a combined carrying amount of $4.5 million at the date of sale. The loss on disposal of $3.2 million for the year ended December 31, 2015, is included in “Operating and maintenance” expense on our consolidated statement of income.

During the years ended December 31, 2016, 2015, and 2014, we recorded $10.6 million, $12.3 million, and $15.6 million, respectively, in non-cash impairment charges related to these assets, which are included in “Asset impairment” on our consolidated statements of income.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

11. VARIABLE INTEREST ENTITIES

Midcoast Operating is a Texas limited partnership. As of December 31, 2016, we owned a 51.6% direct limited partner interest in Midcoast Operating. In addition, we own Midcoast Operating’s general partner, Midcoast OLP GP, L.L.C. EEP owns the remaining limited partner interests in Midcoast Operating. We are the primary beneficiary of Midcoast Operating because (1) through our ownership in Midcoast Operating’s general partner and our majority limited partner interest, we have the power to direct the activities that most significantly impact Midcoast Operating’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to Midcoast Operating. In addition, we are the entity within the related party group that is most closely associated with Midcoast Operating.

As of December 31, 2016 and 2015, our consolidated statements of financial position include total assets of $4,901.4 million and $5,241.5 million, respectively, and total liabilities of $297.5 million and $323.7 million, respectively, related to Midcoast Operating. The assets of Midcoast Operating can only be used to settle their obligations, which include a cross-guarantee under MEP’s senior revolving credit facility, or the Credit Agreement and a guarantee of MEP’s senior notes. We do not have an obligation to provide financial support to Midcoast Operating other than by virtue of certain contractual obligations prescribed by the terms of certain indemnities and guarantees to pay certain liabilities of Midcoast Operating in the event of a default.

The following table includes assets to be used to settle liabilities of Midcoast Operating and liabilities of Midcoast Operating for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in our consolidated balance sheet.

 

     December 31,  
     2016      2015  
     (in millions)  

ASSETS

     

Cash and cash equivalents

   $ 4.1      $ 3.4  

Restricted cash

   $ —        $ 6.0  

Receivables, trade and other, net

   $ 8.5      $ 13.3  

Due from General Partner and affiliates

   $ 4.2      $ 46.9  

Accrued receivables

   $ 20.8      $ 56.1  

Inventory

   $ 28.1      $ 31.9  

Other current assets

   $ 60.7      $ 118.5  

Property, plant and equipment, net

   $ 4,114.5      $ 4,226.3  

Equity investment in joint ventures

   $ 360.7      $ 372.3  

Intangible assets, net

   $ 251.8      $ 272.9  

Other assets, net

   $ 48.0      $ 93.9  

LIABILITIES

     

Accounts payable and other

   $ 66.9      $ 87.1  

Due to General Partner and affiliates

   $ 15.8      $ 28.5  

Accrued purchases

   $ 171.8      $ 143.8  

Property and other taxes payable

   $ 17.2      $ 18.4  

Other long-term liabilities

   $ 25.8      $ 45.9  

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

12. EQUITY INVESTMENTS IN JOINT VENTURES

The following table presents our equity investments in joint ventures at the dates indicated. We account for these investments using the equity method.

 

     Ownership
Interest
    December 31,  
           2016      2015  
           (in millions)  

Texas Express Pipeline LLC

     35.0 %   $ 332.8      $ 343.5  

Texas Express Gathering LLC

     35.0 %     27.9        28.8  
    

 

 

    

 

 

 

Total equity investments in joint ventures

     $ 360.7      $ 372.3  
    

 

 

    

 

 

 

Our 35% aggregate investment in and earnings from the Texas Express NGL system are presented in “Equity investment in joint ventures” on our consolidated statements of financial position and “Equity in earnings of joint ventures” on our consolidated statements of income, respectively. These joint ventures are included in our Gathering, processing and transportation segment. The following tables present summarized balance sheet information as of December 31, 2016 and 2015 and summarized income statement information for the years ended December 31, 2016, 2015 and 2014, for the Texas Express NGL system on a combined, 100% basis:

 

     December 31,  
     2016      2015  
     (in millions)  

Current assets

   $ 21.5      $ 24.1  

Non-current assets

   $ 980.3      $ 1,011.3  

Current liabilities

   $ 18.3      $ 21.5  

Non-current liabilities

   $ 1.9      $ 1.5  

Total equity

   $ 981.6      $ 1,012.4  

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Operating revenues

   $ 135.8      $ 130.4      $ 78.7  

Operating expenses

   $ 49.2      $ 45.1      $ 40.7  

Net income

   $ 86.5      $ 85.0      $ 37.9  

We have included in this filing on Form 10-K audited financial statements as of December 31, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014 of Texas Express Pipeline LLC.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

13. INTANGIBLE ASSETS

The following table provides the estimated useful life, gross carrying value, accumulated amortization and net carrying value for each of our major classes of intangible assets:

 

    Estimated
Useful Life
    December 31, 2016     December 31, 2015  
          Gross     Accumulated
Amortization
    Net     Gross     Accumulated
Amortization
    Net  
    (in millions)  

Natural gas supply opportunities

    15 – 30 years     $ 324.1     $ (94.4 )   $ 229.7     $ 324.1     $ (81.9 )   $ 242.2  

Other intangible assets

    3 – 25 years       84.2       (62.1 )     22.1       91.8       (61.1 )     30.7  
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total intangible assets

    $ 408.3     $ (156.5 )   $ 251.8     $ 415.9     $ (143.0 )   $ 272.9  
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Intangible assets primarily include natural gas supply opportunities, which are derived from growth opportunities present in the Barnett Shale producing zone of North Texas and the Granite Wash reservoir of the Anadarko basin in western Oklahoma and the Texas Panhandle. These natural gas supply opportunities primarily consist of dedicated acreage, whereby any prospective producers commencing drilling in areas served by our assets would be required to connect to our systems.

Other intangible assets include software, customer contracts and contributions in aid of construction, or CIACs. These other intangible assets have estimated useful lives that range as short as three years for software to as long as 25 years for CIACs.

For the years ended December 31, 2016, 2015 and 2014, our amortization expense related to intangible assets totaled $22.8 million, $22.0 million and $15.3 million, respectively. The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated as follows in millions:

 

2017

 

2018

 

2019

 

2020

 

2021

$18.0

  $13.5   $13.4   $13.4   $13.4

14. GOODWILL IMPAIRMENT

During May 2015, due to adverse market conditions facing our business, we learned from producers that reductions in drilling will be sustained and prolonged due to continued low prices for natural gas and NGLs. As a result, we determined that the impact on our forecasted operating profits and cash flows for both the gathering, processing and transportation and marketing reporting units for the next five years would be significantly reduced from our prior forecasts.

During the second quarter of 2015, we performed the first step of our goodwill impairment analysis and determined that the carrying value of the gathering, processing and transportation and marketing reporting units exceeded fair value. We completed the second step of the goodwill impairment analysis, comparing the implied fair value of the reporting units to the carrying amounts of goodwill, and determined that goodwill was completely impaired in the amounts of $206.1 million and $20.4 million for the Gathering, Processing and Transportation and Logistics and Marketing segments, respectively. The total impairment charge of $226.5 million is presented as “Goodwill impairment” on our consolidated statement of income for the year ended December 31, 2015. We did not record any goodwill impairments during the years ended December 31, 2016 and 2014.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

14. GOODWILL IMPAIRMENT — (continued)

 

We measured the fair value of our reporting units primarily by using a discounted cash flow analysis. In addition, we also considered overall market capitalization of our business, cash flow measurement data and other factors. Our estimate of fair value required us to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of our gathering, processing and transportation and marketing reporting units.

15. ACCOUNTS PAYABLE AND OTHER

Accounts payable and other are comprised of the following:

 

     December 31,  
     2016      2015  
     (in millions)  

Short term portion of derivative liabilities (see Note 20)

     50.8        45.7  

Trade accounts payable

   $ 11.2      $ 15.8  

Operating accrued liabilities and other

     11.1        31.1  
  

 

 

    

 

 

 

Total accounts payable and other

   $ 73.1      $ 92.6  
  

 

 

    

 

 

 

16. DEBT

The following table presents the carrying amounts of our consolidated debt obligations.

 

     Interest Rate     December 31,  
           2016      2015  
           (in millions)  

Credit Agreement due September 2018

     2.990 %   $ 420.0      $ 490.0  

Series A Senior Notes due September 2019

     3.560 %     75.0        75.0  

Series B Senior Notes due September 2021

     4.040 %     175.0        175.0  

Series C Senior Notes due September 2024

     4.420 %     150.0        150.0  
    

 

 

    

 

 

 

Total principal amount of debt obligations

       820.0        890.0  

Unamortized debt issuance costs

       (1.5 )      (1.8 )
    

 

 

    

 

 

 

Total

     $ 818.5      $ 888.2  
    

 

 

    

 

 

 

Interest Cost

Our interest cost for the years ended December 31, 2016, 2015, and 2014, is comprised of the following:

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Interest cost incurred

   $ 33.3      $ 31.1      $ 17.8  

Less: Interest capitalized

     —          1.6        1.1  
  

 

 

    

 

 

    

 

 

 

Interest expense, net

   $ 33.3      $ 29.5      $ 16.7  
  

 

 

    

 

 

    

 

 

 

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

16. DEBT — (continued)

 

Maturities of Third Party Debt

The scheduled maturities of outstanding third-party debt, excluding any discounts at December 31, 2016, are summarized as follows:

 

     (in millions)  

2017

   $ —    

2018

     420.0  

2019

     75.0  

2020

     —    

2021

     175.0  

Thereafter

     150.0  
  

 

 

 

Total

   $ 820.0  
  

 

 

 

Debt Arrangements

Credit Agreement

We, Midcoast Operating, and our material domestic subsidiaries, are party to the Credit Agreement, by and among us, as co-borrower and a guarantor, Midcoast Operating, as co-borrower and a guarantor, and our material subsidiaries as guarantors.

The Credit Agreement is a committed senior revolving credit facility (with related letter of credit and swing line facilities) that permits aggregate borrowings of up to, at any one time outstanding, $670.0 million, including up to initially: (1) $90.0 million under the letter of credit facility; and (2) $75.0 million under the swing line facility. Subject to customary conditions, we may request that the lenders’ aggregate commitments be increased to an amount not to exceed $1.0 billion.

On September 3, 2015 we amended our Credit Agreement and decreased the aggregate commitments from the initial aggregate borrowing availability of $850.0 million to $810.0 million. The original term of the Credit Agreement was three years, with an initial maturity date of November 13, 2016, subject to four one-year requests for extension at the lenders’ discretion, two of which we have utilized. On September 3, 2015, we further amended our Credit Agreement to extend the maturity date from September 30, 2017 to September 30, 2018; however, $140.0 million of commitments expired on the original maturity date of November 13, 2016, and an additional $25.0 million of commitments will expire on September 30, 2017.

Loans under the Credit Agreement accrue interest at a per annum rate by reference, at our election, to the Eurodollar rate, which is equal to the London Interbank Offered Rate, or LIBOR, or a comparable or successor rate reasonably approved by the Administrative Agent, or base rate, in each case, plus an applicable margin. The applicable margin on Eurodollar (LIBOR) rate loans ranges from 1.75% to 2.75% and the applicable margin on base rate loans ranges from 0.75% to 1.75%, in each case determined based upon our total leverage ratio (as defined below) at the applicable time. At December 31, 2016, we had $420.0 million in outstanding borrowings under the Credit Agreement at a weighted average interest rate of 2.99%. Under the Credit Agreement, we had net repayments of approximately $70.0 million during the year ended December 31, 2016, which includes gross borrowings of $7,836.3 million and gross repayments of $7,906.3 million.

A letter of credit fee is payable by the borrowers equal to the applicable margin for Eurodollar (LIBOR) rate loans times the daily amount available to be drawn under outstanding letters of credit. A commitment fee is

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

16. DEBT — (continued)

 

payable by us equal to an applicable margin times the daily unused amount of the lenders’ commitment, which applicable margin ranges from 0.30% to 0.50% based upon our total leverage ratio at the applicable time.

Each of our domestic material subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the borrowers arising under the Credit Agreement and other loan documents, and each co-borrower has guaranteed all such indebtedness and liabilities of the other co-borrower. The credit facility is unsecured, but security will be provided upon occurrence of any of the following: (1) for two consecutive quarters, the total leverage ratio as described above, exceeds 4.25 to 1.00, or 4.75 to 1.00 during acquisition periods, (2) uncured breach of certain terms and conditions of the Credit Agreement and (3) obtaining a non-investment grade initial debt rating from either S&P or Moody’s.

Additionally, our Credit Agreement contains various covenants and restrictive provisions which limit our ability and that of Midcoast Operating and their subsidiaries to incur certain liens or permit them to exist, merge or consolidate with another company, dispose of assets, make distributions on or redeem or repurchase their equity interests during the continuance of a default, incur or guarantee additional debt, repay subordinated debt prior to maturity, make certain investments and acquisitions, alter their lines of business, enter into certain types of transactions with affiliates and enter into agreements that restrict their ability to perform certain obligations under the Credit Agreement or to make payments to a borrower or any of their material subsidiaries.

Our Credit Agreement also requires compliance with two financial covenants. We are not permitted to allow our ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.

At December 31, 2016, we were in compliance with the terms of our financial covenants in the Credit Agreement. Due to the extended low commodity price environment and the potential implications on our results of operations, it is likely that we may not meet the total leverage ratio financial covenant at some point during 2017 without further action on our part. Failure to comply with one or both of the financial covenants may result in the occurrence of an event of default under the Credit Agreement, which would result in a cross-default under the note purchase agreement relating to our senior notes. If an event of default were to occur, the lenders could, among other things, terminate their commitments under the Credit Agreement, demand immediate payment of all amounts borrowed by us and Midcoast Operating, trigger the springing liens, and require adequate security or collateral for all outstanding letters of credit outstanding under the facility. In addition, we and Midcoast Operating are restricted under the Credit Agreement from making distributions if there is a continuing default under certain covenants, including the financial covenants. If we are not able to meet the total leverage ratio financial covenant, EEP has indicated to us that it expects to provide certain additional capital contributions to prevent a default under the Credit Agreement. We would also seek a waiver from our lenders, pursue refinancing of the amounts outstanding under the Credit Agreement, or seek to take other action to prevent a default under the Credit Agreement, although there is no assurance that we could obtain any such necessary preventative actions.

These covenants are subject to exceptions and qualifications set forth in the Credit Agreement. At such time as we obtain an investment grade rating from either Moody’s or S&P, certain covenants under the Credit Agreement will no longer be applicable to either the borrowers or the guarantors, or in some instances, any of them (including, but not limited to, the obligation to provide security in certain circumstances, certain restrictions

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

16. DEBT — (continued)

 

on liens, investments and debt, and restrictions on dispositions). The Credit Agreement also contains customary representations, warranties, indemnities and remedies provisions.

In connection with an amendment to our Credit Agreement in 2014, we entered into an amended and restated subordination agreement by and among us, Midcoast Operating, the other parties from time to time party thereto and EEP in favor of an administrative agent, and for the benefit of the administrative agent and the lenders party to the Credit Agreement, to accommodate the subordination agreement entered into in connection with the Purchase Agreement, described below under “Senior Notes.”

Senior Notes

On September 30, 2014, we completed a private offering of $400.0 million of notes consisting of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. We pay interest on all of the Notes semi-annually on March 31 and September 30, commencing on March 31, 2015. We received approximately $398.1 million in net proceeds, which were used to repay outstanding indebtedness and for other general partnership purposes. Using a portion of the net proceeds, we settled two interest rate swaps for a net payment of $0.9 million on September 30, 2014, which will be amortized to interest expense over the original five year hedge term.

The Notes were issued pursuant to a Note Purchase Agreement, or the Purchase Agreement, between us and the purchasers named therein. The Notes and all other obligations under the Purchase Agreement are unconditionally guaranteed by each of our domestic material subsidiaries pursuant to a guaranty agreement. Upon certain trigger events, we and the guarantors will grant liens in our assets (subject to certain excluded assets) to secure the obligations under the Notes. There are currently no liens associated with the Notes. The lien triggers becomes inoperable if we obtain an investment grade rating from either Moody’s or S&P.

Additionally, the Purchase Agreement contains various covenants and restrictive provisions which limit the ability of us and our subsidiaries to incur certain liens or permit such liens to exist, merge or consolidate with another company, dispose of assets, make distributions on or redeem or repurchase their equity interests, incur or guarantee additional debt, repay subordinated debt or certain debt owed to affiliates prior to maturity, alter our lines of business, and enter into certain types of transactions with affiliates or subsidiaries that we are permitted to designate as unrestricted subsidiaries.

The Purchase Agreement contains events of default, indemnities, and covenants customary for transactions of this nature. These covenants and restrictive provisions are subject to exceptions and qualifications set forth in the Purchase Agreement. At such time as we obtain an investment grade rating from either Moody’s or S&P, the obligation to provide security in certain circumstances will no longer be applicable to the Partnership or the guarantors and certain restrictions on prepayments of certain subordinated and affiliate will become less restricted.

The Purchase Agreement also requires compliance with two financial covenants. We must not permit the ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We also must maintain, on a consolidated basis, as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four quarter period then ended of at least 2.50 to 1.00.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

16. DEBT — (continued)

 

At December 31, 2016, we were in compliance with the terms of our financial covenants under the Purchase Agreement. However, due to the extended low commodity price environment and the potential implications on our results of operations, it is likely that we may not meet the total leverage ratio financial covenant at some point during 2017 without further action on our part. Any failure to comply with one or both of the financial covenants could result in an event of default under the Purchase Agreement and the Notes and result in a cross-default under the Credit Agreement. If an event of default were to occur, the note holders could, among other things, demand immediate payment of the Notes and trigger the springing liens. In addition, we and Midcoast Operating are restricted under the Credit Agreement from making distributions if there is a continuing default under certain covenants, including the financial covenants. Any restrictions in our revolving credit facility could adversely affect our business, financial condition, and results of operations. If we are not able to meet the total leverage ratio financial covenant, EEP has indicated to us that it expects to provide certain additional capital contributions to prevent a default under the Credit Agreement. We would also seek a waiver from the note holders, pursue refinancing of the amounts outstanding under the Notes, or seek to take other action to prevent a default under the Purchase Agreement and the Notes, although there is no assurance that we could obtain any such necessary preventative actions.

The Notes are prepayable at our option, in whole or in part, provided that any such prepayment may incur a “make-whole” premium as specified in the Purchase Agreement. We must offer to prepay the notes upon the occurrence of any change of control. Under the Purchase Agreement, a change of control occurs if EEP or Enbridge ceases to control, directly or indirectly, our general partner. In addition, we must offer to prepay the Notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets.

In connection with our entry into the Purchase Agreement, we, along with EEP and the guarantors, entered into a subordination agreement pursuant to which EEP agreed to subordinate its right to payment on obligations owed by Midcoast Operating under the Financial Support Agreement by and between EEP and Midcoast Operating, and liens, if secured, to the rights of the holders under the Purchase Agreement, subject to the terms and conditions of the subordination agreement in favor and for the benefit of the holders of the Notes.

Available Credit

At December 31, 2016, we had approximately $250.0 million of unutilized commitments under the terms of our Credit Agreement, determined as follows:

 

     (in millions)  

Total commitments under Credit Agreement

   $ 670.0  

Amounts outstanding under Credit Agreement

     (420.0 )
  

 

 

 

Total unutilized commitments at December 31, 2016

   $ 250.0  
  

 

 

 

Fair Value of Debt Obligations

The carrying amount of our outstanding borrowings under the Credit Agreement approximates the fair value at December 31, 2016 and 2015, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The outstanding borrowings under the Credit Agreement are included with our long-term debt obligations since we have the ability and the intent to refinance the amounts outstanding on a long-term basis.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

16. DEBT — (continued)

 

The approximate fair values of our fixed-rate debt obligations were $411.4 million and $364.0 million at December 31, 2016 and 2015, respectively. We determined the approximate fair values using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.

17. ASSET RETIREMENT OBLIGATIONS

The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for each of the years ended December 31, 2016 and 2015:

 

     2016      2015  
     (in millions)  

Balance at beginning of period

   $ 3.2      $ 3.0  

Accretion expense

     0.2        0.2  
  

 

 

    

 

 

 

Balance at end of period

   $ 3.4      $ 3.2  
  

 

 

    

 

 

 

ARO liabilities are included in “Other long-term liabilities” on our consolidated statements of financial position. We do not have any assets that are legally restricted for purposes of settling our ARO liabilities at December 31, 2016 and 2015. In our consolidated statements of income for each of the years ended December 31, 2016, 2015 and 2014, we recorded accretion expense of $0.2 million for ARO liabilities.

18. PARTNERS’ CAPITAL

As of December 31, 2016 and 2015, our capital accounts consist of general partner interests held by Midcoast Holdings, which is a wholly-owned subsidiary of EEP, and limited partner interests held by EEP and the public. At December 31, 2016 and 2015, our equity interests were distributed as follows:

 

     December 31,  
     2016     2015  

Limited Partner interest held by EEP

     52 %     52 %

Limited Partner interest held by the Public

     46 %     46 %

General Partner interest

     2 %     2 %
  

 

 

   

 

 

 
     100 %     100 %
  

 

 

   

 

 

 

As a result of the Merger Agreement, EECI will acquire all of our outstanding publicly held common units. The transaction is expected to close in the second quarter of 2017, subject to customary conditions. Upon closing, we will cease to be a publicly traded partnership or to file reports under the rules and regulations of the SEC. For further details, refer to Note 1. Organization and Nature of Operations.

Subordinated Units

EEP owned all of our subordinated units. For any quarter during the subordination period, holders of the subordinated units were not be entitled to receive any distribution until holders of Class A common units

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

18. PARTNERS’ CAPITAL — (continued)

 

received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. Subordinated units were not eligible to accrue arrearages and holders of Class A common units received a special allocation of gross income for each taxable year during which subordinated units were outstanding that would otherwise have been allocable to holders of subordinated units.

The subordination period began on the closing date of the Offering and extended until the first business day following the date that we had earned and paid distributions of at least (1) $1.25 (the annualized minimum quarterly distribution) on each of the outstanding common units, subordinated units and general partner units for each of three consecutive, non-overlapping four quarter periods ending on or after December 31, 2016, or (2) $1.875 (150% of the annualized minimum quarterly distribution) on each of the outstanding common units, subordinated units and general partner units and the related distributions on the incentive distribution rights for any four-quarter period ending on or after December 31, 2014, in each case provided there are no arrearages in payment of the minimum quarterly distributions on our common units at that time.

The subordination period ended on February 15, 2017. On that date, the outstanding subordinated units converted into a new class of common units, which we refer to as Class B common units, on a one-for-one basis, and all Class A common units are no longer entitled to arrearages. There were no arrearages during the subordination period.

Distribution to Partners

The following table sets forth our distributions, as approved by the board of directors of our General Partner, during the year ended December 31, 2016.

 

Distribution Declaration Date

   Record Date      Distribution
Payment Date
     Distribution
per Unit
     Cash
Distributed
 
                   (in millions, except per unit amounts)  

2016

           

October 27

     November 7      November 14      $ 0.35750      $ 16.5  

July 27

     August 5        August 12      $ 0.35750      $ 16.5  

April 28

     May 6        May 13      $ 0.35750      $ 16.5  

January 28

     February 5        February 12      $ 0.35750      $ 16.5  
           

 

 

 
            $ 66.0  
           

 

 

 

2015

           

October 29

     November 6        November 13      $ 0.35750      $ 16.5  

July 29

     August 7        August 14      $ 0.35250      $ 16.3  

April 29

     May 8        May 15      $ 0.34750      $ 16.0  

January 28

     February 6        February 13      $ 0.34250      $ 15.8  
           

 

 

 
              64.6  
           

 

 

 

2014

           

October 30

     November 7        November 14      $ 0.33750      $ 15.6  

July 30

     August 7        August 14      $ 0.32500      $ 15.0  

April 29

     May 8        May 15      $ 0.31250      $ 14.4  

January 29

     February 7        February 14      $ 0.16644      $ 7.7  
           

 

 

 
              52.7  
           

 

 

 

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

18. PARTNERS’ CAPITAL — (continued)

 

Cash distributed to partners is reflected in “Distributions to partners,” on our consolidated statements of cash flows. We paid cash distributions to EEP for its ownership interest in us totaling $35.6 million and $34.8 million for the years ended December 31, 2016 and 2015, respectively.

Distributions to Noncontrolling Interests

Midcoast Operating paid cash distributions to EEP for its ownership interest in Midcoast Operating totaling $82.5 million and $97.7 million for the years ended December 31, 2016 and 2015, respectively. These amounts are reflected in “Distributions to noncontrolling interest” in our consolidated statements of cash flows.

On July 29, 2015, the partners of Midcoast Operating approved an amendment to Midcoast Operating’s limited partnership agreement that would potentially enhance our distributable cash flow, demonstrating EEP’s further support of our ongoing cash distribution strategy and growth outlook. The amendment provides a mechanism for us to receive increased quarterly distributions from Midcoast Operating and for EEP to receive reduced quarterly distributions if our declared distribution exceeds our distributable cash, as that term is defined in Midcoast Operating’s limited partnership agreement. Midcoast Operating’s adjustment of EEP’s distribution will be limited by EEP’s pro rata share of the Midcoast Operating quarterly cash distribution and a maximum of $0.005 per unit quarterly distribution increase by us. There is no requirement for us to compensate EEP for these adjusted distributions, except for settling our capital accounts with Midcoast Operating in a liquidation scenario. The amendment to the limited partnership agreement and the support it provides to our cash distribution is effective with the quarter ended June 30, 2015, and continues through and including the distribution made for the quarter ending December 31, 2017. For the year ended December 31, 2015, we did not receive an increased allocation of cash distributions from Midcoast Operating as distributable cash flow we generated exceeded the cash distribution amount we declared for payout. For the year ended December 31, 2016, EEP’s distributions from Midcoast Operating were reduced by $15.9 million.

Acquisition of Additional Interests in Midcoast Operating

On July 1, 2014, we acquired a 12.6% limited partner interest in Midcoast Operating from EEP for $350.0 million, which brought our total ownership interest in Midcoast Operating to 51.6%. We recorded the change in our total ownership interest as an equity transaction. No gain on the acquisition was recognized in our consolidated statements of income or comprehensive income. We reduced the book value of the related “Noncontrolling interest” in Midcoast Operating by $622.0 million in our consolidated statements of financial position as of September 30, 2014. The $272.0 million difference between the acquisition price and the book value of the noncontrolling interest was recorded as an increase to the partners’ capital accounts on a pro-rata basis. In addition, accumulated other comprehensive income, or AOCI, of $0.9 million representing the noncontrolling interest of AOCI for Midcoast Operating was reclassified to AOCI attributable to us.

Securities Authorized for Issuance under LTIP

In connection with our LTIP, we filed a registration statement on Form S-8 with the SEC registering the issuance of 3,750,000 Class A common units that are issuable pursuant to awards that may be granted under our LTIP. As of December 31, 2016, we had not granted any awards for, or that are convertible into, Class A common units under our LTIP. Upon closing of the Merger, we plan to terminate the registration statement on Form S-8 and remove the unissued shares from registration. No new awards will be granted under that LTIP and upon payout of the currently outstanding PSUs under the LTIP, we expect to terminate the LTIP. For further details, refer to Note 19. Equity-Based Compensation.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

18. PARTNERS’ CAPITAL — (continued)

 

Shelf-Registration Statement

Effective February 2, 2016, we terminated our shelf registration statement on Form S-3 filed with the Securities and Exchange Commission with a proposed aggregate offering price for all securities registered of $1.5 billion. No issuances were made under this registration statement.

19. EQUITY-BASED COMPENSATION

The 2013 Midcoast Energy Partners, L.P. Long-Term Incentive Plan, or the LTIP, provides for the grant of, from time to time at the discretion of the board of directors of our General Partner or any delegate thereof, subject to applicable law, unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards, provided that while we are an affiliate of Enbridge, awards will only be granted following a recommendation of the board of directors or compensation committee of Enbridge to the board of our General Partner. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders.

No new awards will be granted under that LTIP and the only awards currently granted under the LTIP are Performance Stock Units, or PSUs. PSUs are granted to employees of affiliates of our General Partner performing services on our behalf and provide for cash awards to be paid at the end of the three-year term, at which time the PSUs will vest 100%. Awards are currently calculated by multiplying the number of PSUs outstanding at the end of the performance period by the weighted-average price of our Class A common units for the 20-trading days prior to the maturity of the PSUs and by a performance multiplier. Any cash distributions paid will be notionally reinvested during the term of the PSUs.

The performance multiplier ranges from zero, if our performance fails to meet threshold performance levels, to a maximum of two if we perform within the highest range of its performance targets. The PSUs derive the performance multiplier through a calculation of our distributable cash flow per unit relative to targets established at the time of grant and yield relative to a specified peer group of companies.

The following table presents PSU activity for the periods indicated:

 

     Performance
Stock Units
     Weighted
Average
Remaining
Contractual
Term (years)
     Aggregate
Intrinsic
Value
(in millions)
 

January 1, 2015

     —          

Units granted

     340,900        

Units matured

     —          

Units forfeited

     (2,898 )      

Distribution reinvested

     38,518        
  

 

 

    

 

 

    

 

 

 

December 31, 2015

     376,520        2.0      $ 3.7  
  

 

 

    

 

 

    

 

 

 

Units granted

     546,610        

Units matured

     —          

Units forfeited

     (69,447 )      

Distribution reinvested

     144,371        
  

 

 

    

 

 

    

 

 

 

December 31, 2016

     998,054        1.6      $ 6.0  
  

 

 

    

 

 

    

 

 

 

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

19. EQUITY-BASED COMPENSATION — (continued)

 

PSUs are paid in cash and therefore classified as a liability award. The liability is re-measured at fair value on each reporting date until the award is settled, with the offset for the change in fair value being recorded as compensation expense based on the percentage of the requisite service that has been rendered at the reporting date. During the vesting term, compensation expense is determined based on the number of PSUs outstanding, the current market price of our Class A common units, dividends reinvested, and performance multipliers. The LTIP agreement and the individual award agreements are between our General Partner and the participants in the LTIP agreement. The associated compensation costs and liability are recorded in our consolidated financial statements based on the approved allocation methodology as some of the recipients of our PSUs provide shared services to us, EEP and other Enbridge entities. Similar to other employee compensation costs, Enbridge Employee Services Incorporated, or EESI, will make the PSU payments to the LTIP participants on behalf of us, EEP and other Enbridge entities who will then reimburse EESI for their respective obligation via an affiliate payable for the disbursements made to the participants.

Performance multipliers of 1.25 and 0.25 for the PSU grants in 2016 and 2015, respectively, based on estimates as of December 31, 2016 were used to calculate the compensation expense for the year ended December 31, 2016. A performance multiplier of 1.00 for the PSU grant in 2015, based on estimates as of December 31, 2015 was used to calculate the compensation expense for the year ended December 31, 2015.

For the years ended December 31, 2016 and 2015, compensation expense recorded for the PSUs was $1.0 million and $1.2 million, respectively, of which our allocated share was estimated $0.3 million and $0.4 million, respectively. As of December 31, 2016, the unrecognized compensation expense related to non-vested units granted was $6.4 million, of which our allocated share is estimated to be $1.6 million, and is expected to be fully recognized over a weighted-average period of approximately two years.

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, crude oil and related products in addition to fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding costs of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. We have hedged a portion of our exposure to the variability in future cash flows associated with commodity price risks in future periods in accordance with our risk management policies. Our derivative instruments that are designated for hedge accounting under authoritative guidance are classified as cash flow hedges.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Derivative Positions

Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:

 

     December 31,  
     2016      2015  
     (in millions)  

Other current assets

   $ 44.1      $ 117.3  

Other assets, net

     3.2        39.2  

Accounts payable and other (1)

     (50.8 )      (45.7 )

Other long-term liabilities

     (3.5 )      (18.3 )
  

 

 

    

 

 

 
   $ (7.0 )    $ 92.5  
  

 

 

    

 

 

 

 

(1)  Includes $12.6 million of cash collateral at December 31, 2015.

The changes in the assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of natural gas, NGL and crude oil sales and purchase contracts.

The table below summarizes our derivative balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty):

 

     December 31,  
     2016      2015  
     (in millions)  

Counterparty Credit Quality (1)

     

AA (2)

   $ 2.5      $ 67.6  

A

     (9.8 )      24.1  

Lower than A

     0.3        0.8  
  

 

 

    

 

 

 
   $ (7.0 )    $ 92.5  
  

 

 

    

 

 

 

 

(1)  As determined by nationally-recognized statistical ratings organizations.
(2)  Includes $12.6 million of cash collateral at December 31, 2015.

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our ISDA® financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received in the balances listed above. At December 31, 2016, we did not have any cash collateral on our asset exposures. At December 31, 2015, our short-term liabilities included $12.6 million relating to cash collateral on our asset exposures. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position. As of December 31, 2015, all of our cash collateral was held directly by EEP.

At December 31, 2016, we provided no letters of credit relating to our liability exposures pursuant to the margin thresholds in effect under our ISDA® agreements. At December 31, 2015, we provided letters of credit

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

totaling $7.5 million. The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

We do not currently have a credit rating. For purposes of our ISDA® agreements, we calculate an implied credit rating based on EEP’s credit ratings. In the event that our implied credit ratings were to decline below the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, we would be required to provide additional amounts under our existing letters of credit to meet the requirements of our ISDA® agreements. For example, if our implied credit ratings had been below the lowest level of investment grade at December 31, 2016, we would have been required to provide additional letters of credit in the amount of $11.7 million related to our open positions.

At December 31, 2016 and 2015, we had credit concentrations in the following industry sectors, as presented below:

 

     December 31,  
     2016      2015  
     (in millions)  

United States financial institutions and investment banking entities (1)

   $ (6.4 )    $ 80.8  

Non-United States financial institutions

     (5.7 )      (12.3 )

Integrated oil companies

     1.0        0.6  

Other

     4.1        23.4  
  

 

 

    

 

 

 
   $ (7.0 )    $ 92.5  
  

 

 

    

 

 

 

 

(1)  Includes $12.6 million of cash collateral at December 31, 2015.

Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter, or OTC, derivatives is directly with our counterparty and continues until the maturity or termination of the contracts.

Effect of Derivative Instruments on the Consolidated Statements of Financial Position

 

    Financial Position Location     Asset Derivatives      Liability
Derivatives
 
          Fair Value at
December 31,
     Fair Value at
December 31,
 
          2016      2015      2016      2015  
          (in millions)  

Derivatives not designated as hedging instruments:

            

Commodity contracts

    Other current assets     $ 44.1      $ 117.3      $ —        $ —    

Commodity contracts

    Other assets, net       3.2        39.2        —          —    

Commodity contracts

   
Accounts payable
and other (1)
 
 
    —          —          (50.8 )      (33.1 )

Commodity contracts

   
Other long-term
liabilities
 
 
    —          —          (3.5 )      (18.3 )
   

 

 

    

 

 

    

 

 

    

 

 

 

Total derivative instruments

    $ 47.3      $ 156.5      $ (54.3 )    $ (51.4 )
   

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  Excludes total of $12.6 million of cash collateral at December 31, 2015.

Accumulated Other Comprehensive Income

We record the change in fair value of our highly effective cash flow hedges in accumulated other comprehensive income, or AOCI, until the derivative financial instruments are settled, at which time they are reclassified to earnings. As of December 31, 2016 and 2015, we included in AOCI unrecognized losses of approximately $0.5 million and $0.4 million, respectively, associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated, settled, or terminated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings.

During the year ended December 31, 2015, unrealized commodity hedge gains of $1.5 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We had no commodity hedges de-designated during the year ended December 31, 2016. We estimate that approximately $0.2 million, representing net losses from our cash flow hedging activities based on pricing and positions at December 31, 2016, will be reclassified from AOCI to earnings during the next 12 months.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income

 

Derivatives in Cash Flow
Hedging Relationships

  Amount of Gain
(Loss) Recognized
in AOCI on
Derivative
(Effective Portion)
    Location of Gain
(Loss) Reclassified from
AOCI to Earnings
(Effective Portion)
  Amount of Gain
(Loss) Reclassified from
AOCI
to Earnings
(Effective Portion)
    Location of Gain (Loss)
Recognized in
Earnings on
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing) (1)
    Amount of Gain
(Loss) Recognized in
Earnings on
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness
Testing) (1)
 
          (in millions)        

For the year ended December 31, 2016

 

   

Interest rate contracts

  $ —       Interest expense   $ (0.2 )     Interest expense     $ —    

Commodity contracts

    —       Commodity costs     0.3       Commodity costs       —    
 

 

 

     

 

 

     

 

 

 

Total

  $ —         $ 0.1       $ —    
 

 

 

     

 

 

     

 

 

 

For the year ended December 31, 2015

 

 

Interest rate contracts

  $ —       Interest expense   $ (0.2 )     Interest expense     $ —    

Commodity contracts

    (24.2 )   Commodity costs     32.9       Commodity costs       (4.1 )
 

 

 

     

 

 

     

 

 

 

Total

  $ (24.2 )     $ 32.7       $ (4.1 )
 

 

 

     

 

 

     

 

 

 

For the year ended December 31, 2014

 

   

Commodity contracts

  $ 29.9     Commodity costs   $ (5.8 )     Commodity costs     $ 5.6  
 

 

 

     

 

 

     

 

 

 

 

(1)  Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

Components of Accumulated Other Comprehensive Income/(Loss)

 

     Cash Flow Hedges  
     2016      2015  
     (in millions)  

Balance at January 1

   $ (0.9 )    $ 11.6  

Other comprehensive income before reclassifications (1)

     —          4.4  

Amounts reclassified from AOCI (2) (3)

     0.5        (17.0 )

Tax benefit

     —          0.1  
  

 

 

    

 

 

 

Net other comprehensive loss

   $ 0.5      $ (12.5 )
  

 

 

    

 

 

 

Balance at December 31

   $ (0.4 )    $ (0.9 )
  

 

 

    

 

 

 

 

(1)  Excludes NCI gains of $4.0 million reclassified from AOCI at December 31, 2015.
(2)  Excludes NCI losses of $0.6 million and $15.8 million reclassified from AOCI at December 31, 2016 and 2015, respectively.
(3)  For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Reclassifications from Accumulated Other Comprehensive Income

 

     December 31,  
     2016      2015      2014  
     (in millions)  

Losses (gains) on cash flow hedges:

        

Interest Rate Contracts (1)

   $ 0.2      $ —        $ —    

Commodity Contracts (2) (3)

     0.3        (17.0 )      1.8  
  

 

 

    

 

 

    

 

 

 

Total Reclassifications from AOCI

   $ 0.5      $ (17.0 )    $ 1.8  
  

 

 

    

 

 

    

 

 

 

 

(1)  Loss reported within “Interest expense, net” in the consolidated statements of income.
(2)  Loss (gain) reported within “Commodity costs” in the consolidated statements of income.
(3)  Excludes NCI losses of $0.6 million, $15.8 million and gains of $4.0 million reclassified from AOCI for the years ended December 31, 2016, 2015 and 2014, respectively.

Effect of Derivative Instruments on Consolidated Statements of Income

 

Derivatives Not
Designated as
Hedging Instruments

  

Location of Gain or (Loss)
Recognized in Earnings

   December 31,  
          2016      2015      2014  
          Amount of Gain or (Loss)
Recognized in Earnings (1) (2)
 
          (in millions)  

Commodity contracts

   Commodity sales    $ 0.3      $ (23.3 )    $ 23.7  

Commodity contracts

   Commodity sales — affiliate      —           (0.3 )      0.3  

Commodity contracts

   Commodity costs (3)      (41.7 )      65.7        136.8  
     

 

 

    

 

 

    

 

 

 

Total

      $ (41.4 )    $ 42.1      $ 160.8  
     

 

 

    

 

 

    

 

 

 

 

(1)  Does not include settlements associated with derivative instruments that settle through physical delivery.
(2)  Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
(3)  Includes settlement gains of $70.7 million, $96.3 million, and $8.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.

We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a gross basis. However, the terms of the ISDA®, which govern our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

(whether or not then due), which the non-defaulting party owes to the defaulting party. The effect of the rights of set-off are outlined below:

Offsetting of Financial Assets and Derivative Assets

 

     As of December 31, 2016  
     Gross
Amount of
Recognized
Assets
     Gross Amount
Offset in the
Statement of
Financial Position
     Net Amount
of Assets
Presented in the
Statement of
Financial Position
     Gross Amount
Not Offset in the
Statement of
Financial Position
    Net Amount  
     (in millions)  

Description:

             

Derivatives

   $ 47.3      $ —        $ 47.3      $ (40.2 )   $ 7.1  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

     As of December 31, 2015  
     Gross
Amount of
Recognized
Assets
     Gross Amount
Offset in the
Statement of
Financial Position
     Net Amount
of Assets
Presented in the
Statement of
Financial Position
     Gross Amount
Not Offset in the
Statement of
Financial Position (1)
    Net Amount  
     (in millions)  

Description:

             

Derivatives

   $ 156.5      $ —        $ 156.5      $ (41.5 )   $ 115.0  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(1)  Includes $12.6 million of cash collateral at December 31, 2015.

Offsetting of Financial Liabilities and Derivative Liabilities

 

     As of December 31, 2016  
     Gross
Amount of
Recognized
Liabilities
    Gross Amount
Offset in the
Statement of
Financial Position
     Net Amount
of Liabilities
Presented in the
Statement of
Financial Position
    Gross Amount
Not Offset in the
Statement of
Financial Position
     Net Amount  
     (in millions)  

Description:

            

Derivatives

   $ (54.3 )   $ —        $ (54.3 )   $ 40.2      $ (14.1 )
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 
     As of December 31, 2015  
     Gross
Amount of
Recognized
Liabilities (1)
    Gross Amount
Offset in the
Statement of
Financial Position
     Net Amount
of Liabilities
Presented in the
Statement of
Financial Position
    Gross Amount
Not Offset in the
Statement of
Financial Position (1)
     Net Amount  
     (in millions)  

Description:

            

Derivatives

   $ (64.0 )   $ —        $ (64.0 )   $ 41.5      $ (22.5 )
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

(1)  Includes $12.6 million of cash collateral at December 31, 2015.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy of our net financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.

 

     December 31, 2016     December 31, 2015  
     Level 1      Level 2     Level 3     Total     Level 1      Level 2      Level 3      Total  
     (in millions)  

Commodity contracts:

                    

Financial

   $ —        $ (2.5 )   $ (0.1 )   $ (2.6 )   $ —        $ 1.3      $ 8.9      $ 10.2  

Physical

     —          —         2.6       2.6       —          —          0.6        0.6  

Commodity options

     —          —         (7.0 )     (7.0 )     —          —          94.3        94.3  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 
   $ —        $ (2.5 )   $ (4.5 )   $ (7.0 )   $ —        $ 1.3      $ 103.8      $ 105.1  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

    

 

 

 

Cash Collateral

            —                  (12.6 )
         

 

 

            

 

 

 

Total

          $ (7.0 )            $ 92.5  
         

 

 

            

 

 

 

Qualitative Information about Level 3 Fair Value Measurements

Data from pricing services and published indices are used to measure the fair value of our Level 3 derivative instruments on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (natural gas, NGLs and crude) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Forward commodity price in isolation has a direct relationship to the fair value of a commodity contract in a long position and an inverse relationship to a commodity contract in a short position. Volatility has a direct relationship to the fair value of an option contract. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. A change to the credit valuation has an inverse relationship to the fair value of our derivative contracts.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Quantitative Information About Level 3 Fair Value Measurements

 

Contract Type

  Fair Value at
December 31,
2016 (2)
    Valuation
Technique
    Unobservable
Input
    Range (1)     Units  
                      Lowest     Highest     Weighted
Average
       
    (in millions)                                      

Commodity Contracts — Financial

 

           

Natural Gas

  $ 4.7      
Market
Approach
 
 
   
Forward Natural
Gas Price
 
 
    3.18       3.93       3.58       MMBtu  

NGLs

    (4.8 )    
Market
Approach
 
 
   
Forward NGL
Price
 
 
    0.27       1.23       0.64       Gal  

Commodity Contracts — Physical

 

           

Natural Gas

    0.7      
Market
Approach
 
 
   
Forward Natural
Gas Price
 
 
    2.72       4.16       3.49       MMBtu  

Crude Oil

    (1.2 )    
Market
Approach
 
 
   
Forward Crude Oil
Price
 
 
    39.21       55.62       52.00       Bbl  

NGLs

    3.1      
Market
Approach
 
 
   
Forward NGL
Price
 
 
    0.27       1.31       0.48       Gal  

Commodity Options

 

           

Natural Gas, Crude and NGLs

    (7.0 )     Option Model       Option Volatility       22 %     33 %     25 %  
 

 

 

             

Total Fair Value

  $ (4.5 )            
 

 

 

             

 

(1)  Prices are in dollars per MMBtu for natural gas, dollars per Gallon, or Gal, for NGLs, and Bbl for crude oil.
(2)  Fair values include credit valuation adjustment gains of approximately $0.1 million.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Contract Type

  Fair Value at
December 31,
2015 (2)
    Valuation
Technique
    Unobservable
Input
    Range (1)     Units  
                      Lowest     Highest     Weighted
Average
       
    (in millions)                                      

Commodity Contracts — Financial

 

           

Natural Gas

  $ 0.3      
Market
Approach
 
 
   
Forward Natural
Gas Price
 
 
    2.27       3.07       2.64       MMBtu  

NGLs

    8.6      
Market
Approach
 
 
   
Forward NGL
Price
 
 
    0.16       0.93       0.41       Gal  

Commodity Contracts — Physical

 

           

Natural Gas

    (2.5 )    
Market
Approach
 
 
   
Forward Natural
Gas Price
 
 
    2.08       3.44       2.33       MMBtu  

Crude Oil

    —        
Market
Approach
 
 
   
Forward Crude Oil
Price
 
 
    26.50       38.41       37.29       Bbl  

NGLs

    3.1      
Market
Approach
 
 
   
Forward NGL
Price
 
 
    0.16       1.20       0.40       Gal  

Commodity Options

 

           

Natural Gas, Crude and NGLs

    94.3       Option Model       Option Volatility       13 %     74 %     36 %  
 

 

 

             

Total Fair Value

  $ 103.8              
 

 

 

             

 

(1)  Prices are in dollars per MMBtu for natural gas, Gal for NGLs and Bbl for crude oil.
(2)  Fair values include credit valuation adjustment losses of approximately $0.3 million.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Level 3 Fair Value Reconciliation

The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2016 to December 31, 2016. No transfers of assets between any of the Levels occurred during the period.

 

     Commodity
Financial
Contracts
     Commodity
Physical
Contracts
     Commodity
Options
     Total  
     (in millions)  

Beginning balance as of January 1, 2016

   $ 8.9      $ 0.6      $ 94.3      $ 103.8  

Transfer in (out) of Level 3 (1)

     —          —          —          —    

Gains or losses included in earnings:

           

Reported in Commodity sales

     —          (20.4 )      —          (20.4 )

Reported in Commodity costs

     (2.2 )      24.4        (32.5 )      (10.3 )

Gains or losses included in other comprehensive income:

           

Purchases, issuances, sales and settlements:

           

Purchases

     —          —          —          —    

Sales

     —          —          0.7        0.7  

Settlements (2)

     (6.8 )      (2.0 )      (69.5 )      (78.3 )
  

 

 

    

 

 

    

 

 

    

 

 

 

Ending balance as of December 31, 2016

   $ (0.1 )    $ 2.6      $ (7.0 )    $ (4.5 )
  

 

 

    

 

 

    

 

 

    

 

 

 

Amounts reported in Commodity sales

   $ —        $ 0.3      $ —        $ 0.3  
  

 

 

    

 

 

    

 

 

    

 

 

 

Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets and liabilities still held at the reporting date:

           

Reported in Commodity sales

   $ —        $ (1.5 )    $ —        $ (1.5 )
  

 

 

    

 

 

    

 

 

    

 

 

 

Reported in Commodity costs

   $ 0.9      $ 4.0      $ (21.2 )    $ (16.3 )
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)  Our policy is to recognize transfers as of the last day of the reporting period.
(2)  Settlements represent the realized portion of forward contracts.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at December 31, 2016 and 2015:

 

    At December 31, 2016     At December 31, 2015  
   

 

    Wtd. Average Price (2)     Fair Value     Fair Value (3)  
    Commodity   Notional (1)         Receive             Pay         Asset     Liability     Asset     Liability  
    (in millions)  

Portion of contracts maturing in 2017

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     5,145,880     $ 3.51     $ 3.00     $ 2.6     $ —       $ —       $ —    
  NGL     4,356,500     $ 29.43     $ 24.51     $ 21.4     $ —       $ —       $ (4.5 )
  Crude Oil     736,750     $ 56.00     $ 62.53     $ 0.9     $ (5.6 )   $ —       $ (10.9 )

Receive fixed/pay variable

  NGL     6,006,000     $ 25.74     $ 30.32     $ —       $ (27.5 )   $ 3.3     $ (0.1 )
  Crude Oil     867,750     $ 59.69     $ 55.69     $ 5.7     $ (2.2 )   $ 10.9     $ —    

Receive variable/pay variable

  Natural Gas     22,230,000     $ 3.59     $ 3.49     $ 2.5     $ (0.4 )   $ 0.5     $ (0.2 )

Physical Contracts

               

Receive variable/pay fixed

  Natural Gas     32,400     $ 3.68     $ 3.49     $ —       $ —       $ —       $ —    
  NGL     412,090     $ 23.61     $ 21.56     $ 0.9     $ —       $ —       $ —    

Receive fixed/pay variable

  Natural Gas     69,600     $ 3.56     $ 3.67     $ —       $ —       $ —       $ —    
  NGL     264,380     $ 33.22     $ 37.21     $ —       $ (1.2 )   $ —       $ —    

Receive variable/pay variable

  Natural Gas     49,299,457     $ 3.54     $ 3.52     $ 0.6     $ —       $ 0.1     $ —    
  NGL     8,269,007     $ 21.85     $ 21.61     $ 2.6     $ (0.6 )   $ —       $ —    
  Crude Oil     453,392     $ 50.34     $ 52.85     $ 0.7     $ (2.0 )   $ —       $ —    

Portion of contracts maturing in 2018

               

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     2,193,804     $ 3.16     $ 3.13     $ 0.1     $ —       $ 0.1     $ —    
  NGL     6,756,250     $ 19.36     $ 19.15     $ 1.4     $ —       $ —       $ —    

Portion of contracts maturing in 2019

               

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     2,199,798     $ 2.92     $ 2.90     $ 0.1     $ —       $ 0.1     $ —    

Portion of contracts maturing in 2020

               

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     365,634     $ 3.13     $ 3.10     $ —       $ —       $ —       $ —    

 

(1)  Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)  Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.
(3)  The fair value is determined based on quoted market prices at December 31, 2016 and 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $0.6 million at December 31, 2015 as well as cash collateral received.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

20. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES — (continued)

 

 

 

The following table provides summarized information about the fair value of expected cash flows of our outstanding commodity options at December 31, 2016 and 2015:

 

     At December 31, 2016     At December 31, 2015  
     Commodity      Notional (1)      Strike
Price (2)
     Market
Price (2)
     Fair Value (3)     Fair Value (3)  
                                 Asset      Liability       Asset          Liability    
                                 (in millions)  

Portion of option contracts maturing in 2017

                      

Puts (purchased)

     NGL        1,642,500      $ 25.90      $ 35.05      $ 3.4      $ —       $ 5.8      $ —    
     Crude Oil      638,750      $ 59.86      $ 56.35      $ 4.6      $ —       $ 10.0      $ —    

Calls (written)

     NGL        1,642,500      $ 30.06      $ 35.05      $ —        $ (13.4 )   $ —        $ (0.8 )
     Crude Oil      638,750      $ 68.19      $ 56.35      $ —        $ (1.1 )   $ —        $ (0.6 )

Portion of option contracts maturing in 2018

                      

Puts (purchased)

     Crude Oil        91,250      $ 42.00      $ 56.52      $ 0.2      $ —       $ —        $ —    

Calls (written)

     Crude Oil        91,250      $ 51.75      $ 56.52      $ —        $ (0.8 )   $ —        $ —    

 

(1)  Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.
(2)  Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.
(3)  The fair value is determined based on quoted market prices at December 31, 2016 and 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude any credit valuation adjustment gains of approximately $0.1 million and losses of approximately $0.4 million at December 31, 2016 and 2015, respectively, as well as cash collateral received.

21. INCOME TAXES

We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of franchise tax laws by the State of Texas that apply to entities organized as partnerships, and which is based upon many but not all items included in net income.

We compute our income tax expense by applying a Texas state franchise tax rate to modified gross margin. Our Texas state franchise tax rate was 0.6%, 0.4%, and 0.6%, for the years ended December 31, 2016, 2015, and 2014, respectively. Our income tax expense is summarized below:

 

     2016      2015      2014  
     (in millions)  

Current state

   $ (1.3 )    $ 1.1      $ 1.7  

Deferred state

     3.3        0.3        2.9  
  

 

 

    

 

 

    

 

 

 

Total income tax expense

   $ 2.0      $ 1.4      $ 4.6  
  

 

 

    

 

 

    

 

 

 

Our effective tax rate is calculated by dividing the income tax expense by the pretax net book income or loss. The income base for calculating our income tax expense is modified gross margin for Texas rather than

 

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Table of Contents

MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

21. INCOME TAXES — (continued)

 

pretax net book income or loss. As a result, this difference is the only reconciling item between the statutory and effective income tax rate. Our effective tax rate for the years ended December 31, 2016, 2015, and 2014, is as follows:

 

     2016     2015     2014  
     (in millions)  

Income (loss) before income tax expense

   $ (155.0 )   $ (283.1 )   $ 148.9  

State income tax expense

   $ 2.0     $ 1.4     $ 4.6  

Effective income tax rate

     (1.3 )%      (0.5 )%      3.1 %

During 2015, we assigned certain contracts in our Logistics and Marketing segment to a third party. This transaction increased our Texas state franchise tax apportionment factor. As a result, for the year ended December 31, 2015, we incurred approximately $2.4 million of additional deferred income tax expense in our consolidated statements of income.

The Texas Franchise Tax Reduction Act of 2015 was signed into law on June 15, 2015. The law applies to original reports filed on or after January 1, 2016, and permanently reduces Texas state franchise tax rates. Specifically, the general 1.0% rate was reduced to 0.75%. As a result of this change, we have recorded a reduction in our deferred income tax payable reflected in “Other long-term liabilities” on our consolidated statement of financial position of approximately $3.5 million at December 31, 2015.

At December 31, 2016 and 2015, we have a current income tax refund receivable of $1.0 million and current income tax payable of $1.1 million, respectively. In addition, at December 31, 2016 and 2015, we included a deferred income tax liability of $17.5 million and $14.3 million, respectively, in “Other long-term liabilities,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

Our tax years are generally open to examination by the Internal Revenue Service and state revenue authorities for calendar years ended December 31, 2015, 2014, and 2013.

Accounting for Uncertainty in Income Taxes

For the years ended December 31, 2016, 2015 and 2014, respectively, we have not recorded any amounts for uncertain tax positions.

22. SUPPLEMENTAL CASH FLOWS INFORMATION

 

     For the year ended December 31,  
         2016              2015              2014      
     (in millions)  

Cash paid during the year for:

        

Interest (net of capitalization)

   $ 32.0      $ 27.9      $ 12.0  

Income taxes

   $ 1.8      $ 1.8      $ 1.5  

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

22. SUPPLEMENTAL CASH FLOWS INFORMATION — (continued)

 

Changes in our working capital accounts are shown in the following table:

 

     For the year ended December 31,  
     2016      2015      2014  
     (in millions)  

Receivables, trade and other

   $ 4.8      $ 2.9      $ 33.2  

Due from General Partner and affiliates

     54.0        12.1        608.6  

Accrued receivables

     35.3        173.5        (47.4 )

Inventory

     3.6        43.8        (4.9 )

Current and long-term other assets

     (11.4 )      10.1        (23.9 )

Due to General Partner and affiliates

     14.1        29.6        (468.2 )

Accounts payable and other

     (23.4 )      (11.7 )      (21.2 )

Accrued purchases

     28.0        (231.4 )      (90.5 )

Interest payable

     (0.2 )      0.2        4.7  

Property and other taxes payable

     (1.2 )      (2.5 )      1.1  
  

 

 

    

 

 

    

 

 

 

Changes in operating assets and liabilities

   $ 103.6      $ 26.6      $ (8.5 )
  

 

 

    

 

 

    

 

 

 

In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures (excluding “Acquisitions” and “Investment in joint ventures”):

 

     For the year ended December 31,  
         2016              2015              2014      
     (in millions)  

Total capital expenditures

   $ 56.1      $ 178.5      $ 236.0  

Decrease in construction payables

     10.9        12.6        1.7  
  

 

 

    

 

 

    

 

 

 

Cash used for additions to property, plant and equipment

   $ 67.0      $ 191.1      $ 237.7  
  

 

 

    

 

 

    

 

 

 

23. RELATED PARTY TRANSACTIONS

We do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. Enbridge and its affiliates provide management, administrative, operational and workforce related services to us. Employees of Enbridge and its affiliates are assigned to work for one or more affiliates of Enbridge, including us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.

Omnibus Agreement

We, Midcoast Holdings, EEP, and Enbridge, are parties to the Omnibus Agreement under which EEP agreed to, among other things, indemnify us for certain matters, including environmental, right-of-way and permit matters, and EEP granted us a license to use the Enbridge logo and certain other trademarks and tradenames. The Omnibus Agreement may be terminated by the mutual agreement of the parties, or by either Enbridge or us in the event that EEP ceases to control Midcoast Holdings, provided that our indemnification obligations will remain in full force and effect until they expire in accordance with their respective terms.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

23. RELATED PARTY TRANSACTIONS — (continued)

 

Under the Omnibus Agreement, EEP also agreed to indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets arising prior to the closing of our initial public offering on November 13, 2013, or the Offering, in each case, that are identified prior to the third anniversary of the closing of the Offering. EEP’s obligation to indemnify us for any environmental liabilities is subject to a $500,000 aggregate deductible before we are entitled to indemnification. EEP will also indemnify us for failure to have certain rights-of-way, consents, licenses and permits necessary to own and operate our assets in substantially the same manner in which they were owned and operated prior to the closing of the Offering, including the cost of curing certain such failures that do not allow our assets to be operated in accordance with prudent industry practice, in each case, that are identified prior to the third anniversary of the closing of the Offering. EEP’s obligation to indemnify us for any right-of-way, consent, license or permit matters is subject to a $500,000 aggregate deductible before we are entitled to indemnification. There is a $15.0 million aggregate cap on the amounts for which EEP will indemnify us for environmental, right-of-way, consents, licenses and permit matters under the Omnibus Agreement.

During the year ended December 31, 2016, we received indemnification proceeds from EEP under the Omnibus Agreement of $12.2 million for the acquisition of title to right-of-way assets that were pending at the time of our initial public offering and associated legal fees. There have been no other payments from EEP under the Omnibus Agreement. Indemnification amounts of $9.5 million are classified as a contribution from our General Partner in our consolidated statements of cash flows for the year ended December 31, 2016 and reflected in the General Partner capital account in our consolidated statement of financial position as of December 31, 2016. The remaining $2.7 million is classified as a reduction of legal expenses reflected in “General and administrative — affiliate” expense in our consolidated statements of income for the year ended December 31, 2016.

Intercorporate Services Agreement

We and EEP are parties to an Intercorporate Service Agreement, or the Intercorporate Services Agreement, pursuant to which EEP and its affiliates provide us with the following services:

 

    executive, management, business development, administrative, legal, human resources, records and information management, public affairs, investor relations, government relations and computer support services;

 

    accounting and tax planning and compliance services, including preparation of financial statements and income tax returns, unitholder tax reporting and audit and treasury services;

 

    strategic insurance advice, planning and claims management and related support services, and arrangement of insurance coverage as required;

 

    facilitation of capital markets access and financing services, cash management and related banking services, financial structuring and advisory services, as well as credit support for our subsidiaries and affiliates on an as-needed basis for projects, transactions or other purposes;

 

    operational and technical services, including integrity, safety, environmental, project management, engineering, fundamentals analysis and regulatory, and pipeline control and field operations; and

 

    other services as we may request.

Under the Intercorporate Services Agreement, we reimburse EEP and its affiliates for the costs and expenses incurred in providing us with such services. However, EEP has agreed to reduce the amounts payable for general

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

23. RELATED PARTY TRANSACTIONS — (continued)

 

and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually. As a result, for each of the years ended December 31, 2016 and 2015, we recognized $25.0 million as a reduction to “Due to general partner and affiliates” with an offset recorded as contribution to “Noncontrolling interest” in our consolidated statements of financial position.

The affiliate amounts incurred by us through EEP for services received pursuant to the Intercorporate Services Agreement are reflected in “Operating and maintenance — affiliate” and “General and administrative — affiliate” on our consolidated statements of income. For the periods ended December 31, 2016 and 2015, we recognized workforce reduction costs of $2.5 million and $1.3 million, respectively, which are included in “General and administrative — affiliate” on our consolidated statements of income.

Insurance Allocation Agreement

We participate in the comprehensive insurance program that is maintained by Enbridge for its benefit and the benefit of its subsidiaries. On November 13, 2013, we entered into an Amended and Restated Allocation Agreement, or the Insurance Allocation Agreement, by and among us, Enbridge, EEP and Enbridge Income Fund Holdings Inc., in order to participate in the comprehensive insurance program that Enbridge maintains for itself and its subsidiaries. Under this agreement, in the unlikely event that multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis.

Affiliate Revenues and Purchases

We sell natural gas, NGLs and crude oil at market prices on the date of sale to Enbridge and its affiliates. The sales to Enbridge and its affiliates are presented in “Commodity sales– affiliate” on our consolidated statements of income. We also purchase natural gas, NGLs and crude oil at market prices on the date of purchase from Enbridge and its affiliates for sale to third parties. The purchases from Enbridge and its affiliates are presented in “Commodity costs– affiliate” on our consolidated statements of income.

Also, included in “Commodity costs — affiliate,” are pipeline transportation and demand fees from the Texas Express NGL system of $19.9 million, $18.4 million, and $21.9 million for the years ended December 31, 2016, 2015, and 2014, respectively. Our logistics and marketing business has made commitments to transport up to 120,000 Bpd of NGLs on the Texas Express NGL system through 2022. Our current commitment level is 29,000 Bpd and our average commitment will increase to 75,000 Bpd in 2017.

Routine purchases and sales with affiliates are settled monthly through our centralized treasury function. Routine purchases and sales with affiliates that have not yet been settled are included in “Due from general partner and affiliates” and “Due to general partner and affiliates” on our consolidated statements of financial position.

Sale of Accounts Receivable

We and certain of our subsidiaries are parties to a receivables purchase agreement, which we refer to as the Receivables Agreement, with an indirect wholly-owned subsidiary of Enbridge. The Receivables Agreement and the transactions contemplated thereby were approved by a special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of participating

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

23. RELATED PARTY TRANSACTIONS — (continued)

 

sellers, consisting of certain of our subsidiaries and certain EEP subsidiaries up to an aggregate monthly maximum of $450.0 million, net of receivables that have not been collected. Following the sale and transfer of the receivables to the Enbridge subsidiary, the receivables are deposited in an account of that subsidiary, and ownership and control are vested in that subsidiary. The Enbridge subsidiary has no recourse with respect to the receivables acquired from these operating subsidiaries under the terms of and subject to the conditions stated in the Receivables Agreement.

We and EEP each act in an administrative capacity as collection agent on behalf of the Enbridge subsidiary and can be removed at any time in the sole discretion of the Enbridge subsidiary. We and EEP have no other involvement with the purchase and sale of the receivables pursuant to the Receivables Agreement.

For the years ended December 31, 2016 and 2015, we sold and derecognized $1,713.0 million and $2,157.6 million, respectively, of receivables to an indirect wholly-owned subsidiary of Enbridge. For the years ended December 31, 2016 and 2015, we received cash proceeds of $1,712.2 million and $2,157.0 million, respectively.

Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “General and administrative — affiliate” expense in our consolidated statements of income. For the years ended December 31, 2016, 2015, and 2014, the expense stemming from the discount on the receivables sold was $0.8 million, $0.6 million, and $0.9 million, respectively.

As of December 31, 2016 and 2015, we had $11.0 million and $14.6 million, respectively, in “Restricted cash” on our consolidated statements of financial position for cash collections related to sold and derecognized receivables that have yet to be remitted to the Enbridge subsidiary. As of December 31, 2016 and 2015, outstanding receivables of $199.1 million and $147.1 million, respectively, which had been sold and derecognized had not been collected on behalf of the Enbridge subsidiary.

Financial Support Agreement

Midcoast Operating and EEP are parties to a Financial Support Agreement, pursuant to which EEP will provide letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time outstanding, in support of Midcoast Operating’s and its wholly-owned subsidiaries’ financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly-owned subsidiaries, is a party. This Financial Support Agreement will terminate on November 13, 2017. At December 31, 2016, EEP provided no letters of credit and utilized $39.9 million in guarantees. At December 31, 2015, EEP provided $7.5 million of letters of credit outstanding and utilized $21.7 million in guarantees. Under the Financial Support Agreement, EEP’s support of Midcoast Operating’s and its wholly-owned subsidiaries’ obligations will terminate on the earlier to occur of: (1) the fourth anniversary of the closing of the Offering and (2) the date on which EEP owns, directly or indirectly (other than through its ownership interests in the Partnership), less than 20% of the total outstanding limited partner interest in Midcoast Operating.

The annual costs that Midcoast Operating incurs under the Financial Support Agreement are based on the cumulative average amount of letters of credit and guarantees that EEP provides on behalf of Midcoast Operating and its wholly-owned subsidiaries, multiplied by a 2.5% annual fee. Midcoast Operating incurred $0.5 million and $0.6 million of these costs for the years ended December 31, 2016 and 2015, respectively, which is included in “Operating and maintenance-affiliate” on our consolidated statements of income.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

23. RELATED PARTY TRANSACTIONS — (continued)

 

The Financial Support Agreement also provides that if the Credit Agreement is secured, the Financial Support Agreement also will be secured to the same extent on a second-lien basis. EEP has agreed to subordinate its right to payment on obligations owed under the Financial Support Agreement and liens, if secured, to the rights of the lenders under the Credit Agreement and the Purchase Agreement, subject to the terms and conditions of a subordination agreement.

24. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to the operating activities of our gathering, processing, and transportation and logistics and marketing businesses, and we are, at times, subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or otherwise, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our gathering, processing and transportation and logistics and marketing businesses. We continue to voluntarily monitor past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations. As of December 31, 2016 and 2015, we did not have any material accrued environmental liabilities.

Natural Gas in Custody

Approximately 40% of the natural gas volumes handled by our gathering, processing and transportation business are transported for customers on a contractual basis. We purchase the remaining volumes and sell to third parties downstream of the purchase point. At any point in time, the value of our customers’ natural gas in the custody of our gathering, processing and transportation assets is not significant to our operating results, cash flows, or financial position.

Rights-of-Way

As part of our pipeline construction process, we must obtain certain rights-of-way from landowners whose property the pipeline will cross. Rights-of-way that we buy are capitalized as part of “Property, plant and equipment, net” in our consolidated statements of financial position. Rights-of-way that we lease are expensed. We have recorded expenses of $0.5 million, $0.7 million and $1.5 million for the leased right-of-way agreements for the years ended December 31, 2016, 2015, and 2014, respectively.

Legal and Regulatory Proceedings

We are a participant in a number of legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations or cash flows. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

24. COMMITMENTS AND CONTINGENCIES — (continued)

 

Future Minimum Commitments

As of December 31, 2016, our future minimum commitments that have remaining non-cancelable terms in excess of one year are as follows:

 

    2017     2018     2019     2020     2021     Thereafter     Total  
    (in millions)  

Scheduled maturities of debt obligations (1)

  $ —       $ 420.0     $ 75.0     $ —       $ 175.0     $ 150.0     $ 820.0  

Estimated cash payments for interest (2)

    16.3       16.3       16.5       13.7       13.7       19.9       96.4  

Purchase commitments (3)

    2.2       —         —         —         —         —         2.2  

Operating leases

    18.5       15.2       14.0       13.8       13.9       45.1       120.5  

Right-of-way

    0.5       0.4       0.3       0.6       0.1       —         1.9  

Product purchase obligations (4)

    132.4       83.4       69.9       71.3       71.1       201.6       629.7  

Transportation/Service contract obligations (5)

    115.3       125.7       129.6       125.3       124.7       213.4       834.0  

Fractionation agreement obligations (6)

    74.8       74.8       74.8       75.0       74.8       81.3       455.5  

Other long-term liabilities (7)

    0.2       0.2       0.2       0.2       0.2       0.4       1.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

  $ 360.2     $ 736.0     $ 380.3     $ 299.9     $ 473.5     $ 711.7     $ 2,961.6  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)  Represents scheduled future maturities of our consolidated debt principal obligations. For information regarding our consolidated debt obligations, see Note 16. Debt.
(2)  Estimated cash payments for interest exclude adjustments for derivative agreements and cash payments for interest on variable-rate debt. We borrow and repay at varying amounts and interest rates. For more information on our debt obligations, see Note 16. Debt.
(3)  Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects.
(4)  Represents long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at the approximate market value at the time of delivery.
(5)  Represents the minimum payment amounts for contracts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.
(6)  Represents the minimum payment amounts from contracts for firm fractionation of our NGL supply that we reserve at third party fractionation facilities.
(7)  Includes noncurrent portion of deferred credits. We are unable to estimate deferred income taxes (see Note 21. Income Taxes) since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. We are also unable to estimate asset retirement obligations (see Note 17. Asset Retirement Obligations), environmental liabilities (see above) and hedges payable (see Note 20. Derivative Financial Instruments and Hedging Activities) due to the uncertainty as to the amount and, or, timing of when cash payments will be required.

The purchases made under purchase commitments, product purchase obligations, transportation/service contract obligations and fractionation agreement obligations for the years ended December 31, 2016, 2015 and 2014 totaled $859.4 million, $139.5 million and $1.7 billion, respectively.

Our consolidated operating expenses include lease and rental expense amounts of $5.0 million, $7.0 million and $10.7 million during the years ended December 31, 2016, 2015 and 2014, respectively.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

25. QUARTERLY FINANCIAL DATA (Unaudited)

 

     First     Second     Third     Fourth     Total  
     (in millions, except per unit amounts)  

2016 Quarters

          

Operating revenue

   $ 431.9     $ 427.6     $ 486.0     $ 620.5     $ 1,966.0  

Operating expense

   $ 460.3     $ 488.5     $ 516.3     $ 653.5     $ 2,118.6  

Operating income (loss)

   $ (28.4 )   $ (60.9 )   $ (30.3 )   $ (33.0 )   $ (152.6 )

Net income (loss)

   $ (30.3 )   $ (63.0 )   $ (31.1 )   $ (32.6 )   $ (157.0 )

Net income (loss) attributable to noncontrolling interest

   $ (10.1 )   $ (26.2 )   $ (10.4 )   $ (10.4 )   $ (57.1 )

Net loss attributable to limited partner ownership interests

   $ (19.8 )   $ (36.0 )   $ (20.3 )   $ (21.9 )   $ (98.0 )

Net loss per limited partner unit

   $ (0.44 )   $ (0.79 )   $ (0.45 )   $ (0.49 )   $ (2.17 )

2015 Quarters

          

Operating revenue

   $ 873.5     $ 780.1     $ 661.0     $ 528.1     $ 2,842.7  

Operating expense (1)

   $ 901.8     $ 1,038.6     $ 657.1     $ 527.7     $ 3,125.2  

Operating income (loss)

   $ (28.3 )   $ (258.5 )   $ 3.9     $ 0.4     $ (282.5 )

Net income (loss) (2)

   $ (30.1 )   $ (256.5 )   $ 1.1     $ 1.0     $ (284.5 )

Net income (loss) attributable to noncontrolling interest

   $ (10.1 )   $ (120.0 )   $ 4.7     $ 4.8     $ (120.6 )

Net loss attributable to limited partner ownership interest

   $ (19.6 )   $ (133.7 )   $ (3.5 )   $ (3.7 )   $ (160.5 )

Net loss per limited partner unit

   $ (0.43 )   $ (2.96 )   $ (0.08 )   $ (0.08 )   $ (3.55 )

 

(1)  Second quarter 2015 operating expenses were impacted by a goodwill impairment of $226.5 million. For more information, refer to Note 14, Goodwill Impairment.
(2)  Certain corrections relating to prior quarterly periods in 2015 and having net negative impacts of approximately $3.9 million to net income were recorded during the three months ended December 31, 2015. We consider these corrections to be immaterial to the prior quarterly periods presented for 2015.

26. SUBSEQUENT EVENTS

Distribution to Partners

On January 26, 2017, the board of directors of Midcoast Holdings, acting in its capacity as the General Partner of MEP, declared a cash distribution payable to our unitholders on February 14, 2017. The distribution of our available cash of $16.5 million at December 31, 2016, or $0.3575 per limited partner unit was paid on February 14, 2017 to unitholders of record as of February 7, 2017. We paid $7.6 million to our public Class A common unitholders, while $8.9 million in the aggregate was paid to EEP with respect to its Class A common units and subordinated units and to Midcoast Holdings, with respect to its general partner interest.

Midcoast Operating Distribution

On January 26, 2017, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable on February 14, 2017 to its partners of record as of February 7, 2017. Midcoast Operating paid $27.9 million to us and $7.9 million to EEP.

Subordinated Units

The subordination period ended on February 15, 2017. On that date, the outstanding subordinated units converted into a new class of common units, which we refer to as Class B common units, on a one-for-one basis, and all Class A common units are no longer entitled to arrearages. For further details, refer to Note 18. Partner’s Capital — Subordinated Units.

 

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MIDCOAST ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

26. SUBSEQUENT EVENTS — (continued)

 

Merger Agreement

On January 26, 2017, we entered into the merger agreement with EECI whereby EECI will acquire, for cash, all of our outstanding publicly held common units at a price of $8.00 per common unit for an aggregate transaction value of $170.2 million. For further details, refer to Note 1. Organization and Nature of Operations.

 

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

DISCLOSURE CONTROLS AND PROCEDURES

We, EEP, and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in the reports that we file or submit under the Exchange Act within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our principal executive and principal financial officers, has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2016. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are effective at the reasonable assurance level. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management’s Annual Report on Internal Control Over Financial Reporting

Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f).

The Partnership’s internal control over financial reporting is a process designed under the supervision and with the participation of our principal executive and principal financial officers, and effected by the board of directors of our General Partner, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Partnership’s financial statements for external purposes in accordance with generally accepted accounting principles.

The Partnership’s internal control over financial reporting includes policies and procedures that:

 

    Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect transactions and dispositions of assets of the Partnership;

 

    Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with the authorizations of the Partnership’s management and directors; and

 

    Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the Partnership’s financial statements.

Because of its inherent limitations, the Partnership’s internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with our policies or procedures may deteriorate.

Management assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016, with the participation of our principal executive and principal financial officers, based on the framework established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on this assessment, management concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2016.

 

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The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2016 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in Item 8. Financial Statements and Supplementary Data.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the three months ended December 31, 2016.

Item 9B. Other Information

None.

 

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

We are a limited partnership and have no officers or directors of our own. Set forth below is certain information concerning the directors and executive officers of our General Partner. Directors are elected by the sole member of our General Partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of Midcoast Holdings.

 

Name

   Age     

Position

Dan A. Westbrook

     64      Director and Chairman of the Board

John A. Crum

     64      Director

J. Herbert England

     70      Director

C. Gregory Harper

     52      Director and President

James G. Ivey

     65      Director

Mark A. Maki

     52      Director and Senior Vice President

R. Poe Reed

     61      Director and Vice President & Chief Commercial Officer

Edmund P. Segner III

     63      Director

Noor S. Kaissi

     44      Controller

E. Chris Kaitson

     60      Vice President — Law and Assistant Corporate Secretary

Stephen J. Neyland

     49      Vice President — Finance

Kerry C. Puckett

     55      Vice President — Engineering and Operations, Gathering & Processing

Jonathan N. Rose

     49      Treasurer

Allan M. Schneider

     58      Vice President — Regulated Engineering and Operations

David A. Weathers

     62      Vice President — Business Development U.S. Midstream

DIRECTORS

Dan A. Westbrook

Dan A. Westbrook was appointed Chairman of the Board and elected as a director of our General Partner in October 2013 and also serves on the Audit, Finance & Risk Committee. Mr. Westbrook has also served as a director of EEP’s general partner and Enbridge Management since October 2007, and serves on the Audit, Finance & Risk Committee of both companies, as well as serving on Special Committees of Enbridge Management. Since 2008, he has also served on the board of the Carrie Tingley Hospital Foundation in Albuquerque, New Mexico. From 2001 to 2005, Mr. Westbrook served as president of BP China Gas, Power & Upstream, or BP, and as vice-chairman of the board of directors of Dapeng LNG, a Sino joint venture between BP subsidiary CNOOC Gas & Power Ltd. and other Chinese companies. He held executive positions with BP in Argentina, Houston, Russia, Chicago and the Netherlands before retiring from the company in January 2006. From 2013 to 2016, Mr. Westbrook served as a director of SandRidge Energy, Inc. He is a former director of Ivanhoe Mines, now known as Turquoise Hill Resources Ltd., an international mining company; Synenco Energy Inc., a Calgary-based oil sands company; and Knowledge Systems Inc., a privately-held U.S. company that provided software and consultant services to the oil and gas industry.

Through his long career in the petroleum exploration and production industry, including his other public company directorships and previous service as President of BP China, Mr. Westbrook provides the board of directors with extensive industry experience, leadership skills, international and petroleum development experience, as well as knowledge of our business environment.

 

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John A. Crum

John A. Crum was appointed a director of our General Partner on February 10, 2014 and also was appointed to serve on the Audit, Finance & Risk Committee. Since 2015, Mr. Crum has been managing partner of JAC Energy Partners, L.L.C., a company which provides advice and invests in upstream oil and gas development opportunities. He also presently serves as Chairman of the board of managers for Forty Acres Energy, L.L.C., a privately held exploration and production company. From 2011 to 2014, Mr. Crum served as President and Chief Executive Officer and as director of Midstates Petroleum Company, Inc., where he led the initial public offering of the oil and gas exploration and production company in 2012. He also served on the board of directors of Coskata, Inc., a private biofuel technology company, from 2012 to 2015. From 1995 to 2011, Mr. Crum served in a number of senior management roles for Apache Corporation international divisions, and ultimately served as Co-Chief Operating Officer and President, North America from 2009 to 2011. Some previous positions held by Mr. Crum include Vice President of Engineering and Operations of Aquila Energy Corporation from 1993 to 1995 and District Manager and Regional Manager for Pacific Enterprises Oil Company from 1986 to 1993.

Mr. Crum brings to the board more than forty years of experience in the energy industry in a variety of engineering and management roles, including leadership through an initial public offering.

J. Herbert England

J. Herbert England was elected a director of our General Partner in October 2013 and serves as the Chairman of the Audit Finance & Risk Committee of our General Partner. Mr. England has also served as a director of each of EEP’s general partner and Enbridge Management since July 2012 and serves as the Chairman of the Audit, Finance & Risk Committee of both companies. In addition, Mr. England serves on the Enbridge board of directors for whom he also is Chairman of the Audit, Finance & Risk Committee, and on the board of directors of FuelCell Energy, Inc. He has been Chair & Chief Executive Officer of Stahlman-England Irrigation Inc., a contracting company in southwest Florida, since 2000. From 1993 to 1997, Mr. England was the Chair, President & Chief Executive Officer of Sweet Ripe Drinks Ltd., a fruit beverage manufacturing company. Prior to 1993, Mr. England held various executive positions with John Labatt Limited, a brewing company, and its operating companies, Catelli Inc., a food manufacturing company, and Johanna Dairies Inc., a dairy company.

Mr. England brings to the board of directors a wide range of financial executive experience because of his previous positions, as well as his service with other public company audit committees.

C. Gregory Harper

C. Gregory Harper was appointed to the board of directors of our General Partner on January 30, 2014 and appointed President effective December 31, 2014. He has been the principal executive officer of our General Partner since February 28, 2014. Mr. Harper has also served as a director of each of EEP’s general partner and Enbridge Management since January 30, 2014 and Executive Vice President — Gas Pipelines & Processing since April 30, 2014. Mr. Harper also was appointed as President, Gas Pipelines and Processing for Enbridge effective January 30, 2014. He is also on the board of directors of Sprague Operating Resources LLC since October 2013. Mr. Harper joined Midcoast Holdings and its affiliates from Southwestern Energy Company, where he held the position of Senior Vice President, Midstream since 2013. Prior to joining Southwestern Energy Company, Mr. Harper served CenterPoint Energy, Inc. as Senior Vice President and Group President, Pipelines and Field Services since December 2008. Before joining CenterPoint Energy in 2008, Mr. Harper served as President, Chief Executive Officer and as a Director of Spectra Energy Partners, LP from March 2007 to December 2008. From January 2007 to March 2007, Mr. Harper served as Group Vice President of Spectra Energy Corp., and was Group Vice President of Duke Energy from January 2004 to December 2006. Mr. Harper was Senior Vice President of Energy Marketing and Management for Duke Energy North America from January 2003 until January 2004 and Vice President of Business Development for Duke Energy Gas Transmission and Vice President of East Tennessee Natural Gas, LLC from March 2002 until January 2003. He served on the Board of Directors and as Chairman of the Interstate Natural Gas Association of America from 2013.

 

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Mr. Harper brings to the board insight and in-depth knowledge of our industry. He also provides leadership skills, pipeline operations and management expertise and knowledge of our local community and business environment, which he has gained through his long career in the oil and gas industry.

James G. Ivey

James G. Ivey was appointed a director of our General Partner on February 10, 2014 and also was appointed to serve on the Audit, Finance & Risk Committee. From 2014 to February 2017, Mr. Ivey co-headed Pintail Oil and Gas, an exploration and production company. Mr. Ivey currently serves on the board of directors of privately held independent power producer, National Energy & Gas Transmission, Inc., since 2004 and Mach Gen LLC from 2004 to 2014. His prior experience includes serving Milagro Exploration from 2009 to 2012 in the role of Executive Vice President and Chief Financial Officer from 2009 to 2010 and then President and Chief Executive Officer from 2010 to 2012. From 2006 to 2008, Mr. Ivey was Executive Vice President and Chief Financial Officer of Cobalt International Energy. From 2004 to 2006, Mr. Ivey served Markwest Hydrocarbon as Senior Vice President and Chief Financial Officer. His previous background includes serving as the Corporate Treasurer for each of Williams Companies from 1995 to 2004 and Arkla Gas from 1982 to 1995, as well as other financial and engineering positions with Conoco and Fluor from 1973 to 1981.

Mr. Ivey brings to the board over forty years of experience in the oil and gas industry in the exploration and production areas, as well as Master Limited Partnership, or MLP, midstream experience in engineering, finance and corporate governance.

Mark A. Maki

Mark A. Maki was appointed Senior Vice President of our General Partner in February 2014, and he has served as a director of our General Partner since May 2013. Previously from October 2013 until February 2014, he served as Principal Executive Officer of our General Partner. Mr. Maki previously served as President of our General Partner from May 2013 to October 2013. In October 2016, Mr. Maki was elected to serve Enbridge as Senior Vice President — Finance. He was also appointed President and Principal Executive Officer of EEP’s general partner and Enbridge Management on January 30, 2014 and has served both companies as a director since October 2010. Mr. Maki previously served as President of Enbridge Management and Senior Vice President of EEP’s general partner from October 2010. He also served Enbridge in the functional title of Acting President, Gas Pipelines during 2013. Mr. Maki previously served as Vice President — Finance of EEP’s general partner and Enbridge Management from July 2002 to October 2010. Prior to that time, Mr. Maki served as Controller of EEP’s general partner and Enbridge Management from June 2001, and prior to that, as Controller of Enbridge Pipelines from September 1999.

Mr. Maki brings over thirty years of oil and gas experience to the board having joined Enbridge in 1986 and progressing through a series of accounting and financial roles of increasing responsibility during his tenure in the United States and Canada. Through his broad range of domestic and Canadian experience in the pipeline industry, Mr. Maki provides the board of directors with financial expertise, leadership skills in our industry and knowledge of our local community and business environment.

R. Poe Reed

R. Poe Reed joined Enbridge on September 28, 2015 as Vice President & Chief Commercial Officer of our General Partner and was elected as a director effective November 30, 2015. Previously, Mr. Reed was President and Chief Executive Officer of Caliber Midstream from June 2014 to September 2015. Prior to that Mr. Reed was with CenterPoint Energy from January 2011 through June 2014, most recently from December 2013 through June 2014 serving as Executive Vice President and Chief Commercial Officer for Enable Midstream, an MLP in which CenterPoint Energy holds a majority interest and from January 2011 to December 2013 serving as Senior Vice President and Chief Commercial Officer for Interstate Pipelines for CenterPoint Energy. From July 2009

through January 2011, he served as Vice President of natural gas and NGL marketing at DCP Midstream. Before

 

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joining DCP Midstream, Mr. Reed worked in various executive and non-executive capacities with some of the predecessors of DCP, including Duke Energy Field Services Canada, PanEnergy and Texas Eastern.

Mr. Reed brings to the board over thirty years of experience in the midstream sector of the oil and gas industry as well as commercial operations for transmission pipelines, asset-based trading and optimization facilities and gathering and processing businesses.

Edmund P. Segner III

Edmund P. Segner III was appointed a director of our General Partner on February 10, 2014. Mr. Segner is currently a professor in the Department of Civil and Environmental Engineering at Rice University and serves on the boards of directors of three other companies and audit committees, as follows: Bill Barrett Corp., an oil and gas exploration and production company, since August 2009; Archrock GP LLC, formerly Exterran GP LLC, the general partner of Archrock Partners, L.P., an MLP which provides contract operations since May 2009; and Laredo Petroleum, Inc., a Permian oil and gas exploration and development company since August 2011. Mr. Segner retired from EOG Resources, Inc. in 2008. He had held several offices at EOG during his tenure from 1997 to 2008 including President, Chief of Staff and Director and principal financial officer. Formerly, from 1988 to early 1998, Mr. Segner held several positions with Enron Corporation, including Vice President, Senior Vice President and Executive Vice President. Previously, Mr. Segner also served on the boards of Seahawk Drilling from 2009 to 2011 and of Universal Compression Holdings from 2000 to 2002. He has also served as a member of the board or as a trustee for several nonprofit organizations.

Mr. Segner brings to the board his broad experience in management, his experience with MLPs and his financial expertise as well as his audit committee experience.

EXECUTIVE OFFICERS

Noor S. Kaissi was appointed Controller of our General Partner in July 2013. Ms. Kaissi has also served EEP’s general partner and Enbridge Management as Controller since July 2013. Prior to her appointment as Controller for these companies, Ms. Kaissi served as Chief Auditor and in other managerial roles of EEP’s general partner and Enbridge Management and more recently with our General Partner with responsibility for financial accounting, internal audit and controls from June 2005.

E. Chris Kaitson was appointed Vice President — Law and Assistant Corporate Secretary of our General Partner in May 2013. Mr. Kaitson has served as Vice President — Law and Assistant Corporate Secretary of EEP’s general partner and Enbridge Management since May 2007. Prior to that, he was Assistant General Counsel and Assistant Secretary of EEP’s general partner and Enbridge Management from July 2004. He served as Corporate Secretary of EEP’s general partner and Enbridge Management from October 2001 to July 2004. He was previously Assistant Corporate Secretary and General Counsel of Midcoast Energy Resources, Inc. from 1997 until it was acquired by Enbridge in May 2001.

Stephen J. Neyland was appointed Vice President — Finance of our General Partner in May 2013. Mr. Neyland has served as Vice President — Finance of EEP’s general partner and Enbridge Management since October 2010. Mr. Neyland was previously Controller of EEP’s general partner and Enbridge Management effective September 2006. Prior to his appointment, he served as Controller — Natural Gas from January 2005, Assistant Controller from May 2004 to January 2005 and in other managerial roles in finance and accounting from December 2001 to May 2004. Prior to joining Enbridge, Mr. Neyland was Controller of Koch Midstream Services from 1999 to 2001.

Kerry C. Puckett was appointed Vice President — Engineering and Operations, Gathering & Processing of our General Partner in May 2013. Mr. Puckett also served as Vice President — Engineering and Operations, Gathering & Processing of EEP’s general partner and Enbridge Management from October 2007 to April 2014.

 

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Prior to this appointment, he served as General Manager of Engineering and Operations from 2004 and Manager of Operations from 2002 to 2004. Prior to joining Enbridge, he served as Manager of Business Development for Sid Richardson Energy Services Company.

Jonathan N. Rose was appointed Treasurer of our General Partner in March 2014. Mr. Rose was also appointed Treasurer of EEP’s general partner and Enbridge Management in March 2014. Additionally, Mr. Rose serves Enbridge in the role of Director, Treasury since 2014. Mr. Rose’s prior roles with Enbridge include Director, Business Development of Enbridge Pipelines Inc. from April 2010 to March 2014 and Treasurer of EEP’s general partner and Enbridge Management from January 2008 to April 2010. He was previously Assistant Treasurer of EEP’s general partner and Enbridge Management from July 2005 to December 2008. Mr. Rose was also Director, Finance of Enbridge, a position he held from October 2007 to 2010, prior to which he was Manager, Finance from 2004 to December 2008. Prior to that Mr. Rose was a Vice President with Citigroup Global Corporate and Investment Bank from 2001 to 2004.

Allan M. Schneider was appointed Vice President — Regulated Engineering and Operations of our General Partner in May 2013. Mr. Schneider has served as Vice President, Regulated Engineering and Operations of EEP’s general partner and Enbridge Management since October 2007. Prior to his appointment, he served as Director of Engineering and Operations for Regulated & Offshore and Director of Engineering Services from January 2005. Prior to that, Mr. Schneider was Vice President of Engineering and Operations for Shell Gas Transmission, L.L.C. from December 2000.

David A. Weathers was appointed Vice President — Business Development U.S. Midstream of our General Partner in July 2014. Previously, Mr. Weathers was Sr. Director, Midstream at Southwestern Energy from October 2013 to July 2014. Prior to joining Southwestern Energy, he was Director and Sr. Director, US Gas Assets of NextEra Energy from July 2008 to October 2013. Before joining NextEra, Mr. Weathers served as General Manager, Business Development for Spectra Energy and various other positions spanning over 30 years with Spectra’s predecessor companies.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Exchange Act requires our directors, executive officers and 10% beneficial owners to file with the SEC reports of ownership and changes in ownership of our equity securities and to furnish us with copies of all reports filed. Based on our review of the Section 16(a) filings that have been received by us and the written representations made by our directors and executive officers, we believe that all filings required to be made under Section 16(a) during 2016 were timely made.

GOVERNANCE MATTERS

We are a “controlled company,” as that term is used in NYSE Rule 303A, because all of our voting units are owned by our General Partner. Because we are a controlled company, the NYSE listing standards do not require that we or our General Partner have a majority of independent directors or a nominating or compensation committee of our General Partner’s board of directors.

The NYSE listing standards require our principal executive officer to annually certify that he is not aware of any violation by the Partnership of the NYSE corporate governance listing standards. Accordingly, this certification was provided as required to the NYSE on February 26, 2016.

CODE OF ETHICS, STATEMENT OF BUSINESS CONDUCT AND CORPORATE GOVERNANCE GUIDELINES

We have adopted a Code of Ethics applicable to our General Partner’s senior officers, including the principal executive officer, principal financial officer and principal accounting officer. We also have a statement

 

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of Corporate Governance Guidelines that sets forth the expectation of how our board of directors should function and its position with respect to key corporate governance issues. We also have a Statement of Business Conduct applicable to all of our employees, officers and directors. Copies of the Code of Ethics for Senior Financial Officers. The Corporate Governance Guidelines, and the Statement of Business Conduct are available on our website at www.midcoastpartners.com. We post on our website any amendments to or waivers of our Code of Ethics for Senior Officers or our Statement of Business Conduct, or any amendments to our Corporate Governance Guidelines, and we intend to satisfy any disclosure requirements that may arise under Form 8-K relating to this information through such postings. Additionally, these materials are available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Midcoast Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

AUDIT, FINANCE & RISK COMMITTEE

The General Partner has an Audit, Finance & Risk Committee, referred to as the “Audit Committee,” comprised of four board members who are independent as the term is used in Section 10A of the Exchange Act. None of these members are relying upon any exemptions from the foregoing independence requirements. The members of the Audit Committee are John A. Crum, J. Herbert England, James G. Ivey and Dan A. Westbrook. J. Herbert England is chairman of the Audit Committee. The Audit Committee provides independent oversight with respect to our internal controls, accounting policies, financial reporting, internal audit function and the report of the independent registered public accounting firm. The Audit Committee also reviews the scope and quality, including the independence and objectivity, of the independent and internal auditors and the fees paid for both audit and non-audit work and makes recommendations concerning audit matters, including the engagement of the independent auditors, to the Board of Directors.

The charter of the Audit Committee is available on our website at www.midcoastpartners.com. The charter of the Audit Committee complies with the listing standards of the NYSE currently applicable to us. This material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Midcoast Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

The General Partner’s Board of Directors has determined that J. Herbert England and James G. Ivey each qualify as “audit committee financial experts” as defined in Item 407(d)(5)(ii) of Regulation S-K. Each of the members of the Audit Committee is independent as defined by Section 303A of the listing standards of the NYSE.

Mr. England serves on the audit committees of the General Partner and the general partner of Enbridge Energy Partners, L.P., Enbridge Management, FuelCell Energy, Inc., and Enbridge Inc. In compliance with the provisions of the Audit Committee Charter, the boards of directors of the General Partner and of Enbridge Management and the general partner of Enbridge Energy Partners, L.P. have determined that Mr. England’s simultaneous service on such audit committees does not impair his ability to effectively serve on the Audit Committee.

The General Partner’s Audit Committee has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. Persons wishing to communicate with our Audit Committee may do so by writing to the Chairman, Audit Committee, c/o Midcoast Holdings, L.L.C., 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

EXECUTIVE SESSIONS OF NON-MANAGEMENT DIRECTORS

The independent directors of the General Partner meet at regularly scheduled executive sessions without management. Dan A. Westbrook serves as the presiding director at those executive sessions. Persons wishing to communicate with the Company’s independent directors may do so by writing to the Chairman, Board of Directors, Midcoast Holdings, L.L.C., 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

 

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Item 11. Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

General

We are an MLP and do not directly employ any employees, nor do we have executive officers or directors. We are managed by our General Partner and the executive officers of our General Partner, from which our Named Executive Officers, or NEOs, are determined. Our General Partner is wholly owned and controlled by EEP, which is also an MLP and does not directly employ any employees. We entered into an intercorporate services agreement with EEP, which is managed and controlled by Enbridge Management, to provide us with managerial, administrative and operational services. EEP’s general partner, Enbridge Management and Enbridge, through its affiliates, provide managerial, administrative, operational and director services to EEP pursuant to service agreements among them and EEP. Pursuant to our intercorporate services agreement, we reimburse EEP for an allocated portion of the costs of these services, which costs include a portion of the compensation of the NEOs.

The board of directors of our General Partner does not have a compensation committee, nor does it have responsibility for approving the elements of compensation for the NEOs presented in the tables following this discussion. The board of directors of our General Partner, as part of our annual budgeting process, however, does have responsibility for evaluating and determining the reasonableness of our overall budget. The budget includes compensation amounts to be allocated to us for managerial, administrative, operational and director support to be provided by our General Partner, EEP and its affiliates pursuant to the intercorporate service agreement mentioned above. The budgeted amount of total compensation includes the portion of the compensation of the NEOs that will be allocated to us and is discussed in more detail below.

Since we do not have direct employees or directors, and our General Partner does not have responsibility for approving the elements of compensation for the NEOs, we and our General Partner do not have compensation policies. The compensation policies and philosophy of Enbridge govern the types and amounts of compensation of each of the NEOs. The NEOs at December 31, 2016 were:

 

    C. Gregory Harper, President (Principal Executive Officer) and Director

 

    Stephen J. Neyland, Vice President — Finance (Principal Financial Officer)

 

    E. Chris Kaitson, Vice President — Law & Assistant Corporate Secretary

 

    Kerry C. Puckett, Vice President — Engineering and Operations, Gathering and Processing

 

    R. Poe Reed, Vice President & Chief Commercial Officer

Mr. Harper is also an executive officer of Enbridge and serves as President, Gas Pipelines & Processing of Enbridge. Since Mr. Harper is also an executive officer of Enbridge, the Human Resources and Compensation Committee of the board of directors of Enbridge, or the HRC Committee, approves the elements of compensation for him based on the recommendation of the President & Chief Executive Officer of Enbridge considering Mr. Harper’s position within Enbridge on an enterprise-wide basis. Furthermore, Messrs. Neyland and Harper are also officers of EEP’s general partner and Enbridge Management.

The HRC Committee does not have responsibility for reviewing or approving compensation for employees on an individual basis who are not part of Enbridge’s executive leadership team. Compensation of our NEOs, with the exception of Mr. Harper, is determined as part of an Enbridge enterprise-wide review process. Each business unit develops a salary increase budget recommendation, in consultation with the Enbridge corporate compensation department, based on a competitive analysis of the labor market for that business unit. These recommendations are presented, in summary and on a business unit basis, to the HRC Committee for approval. Individual salary increases are implemented after the HRC Committee approves the overall budget.

 

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Compensation adjustments for the remaining NEOs are recommended by their supervisors and reviewed by the executive leadership team of Enbridge, including the President & Chief Executive Officer of Enbridge. Enbridge’s President & Chief Executive Officer approves the individual salary increase recommendations, on an enterprise-wide basis, to ensure that compensation expense is within the budget approved by the HRC Committee. Each of the NEOs provides services to other affiliates of Enbridge and, therefore, compensation is determined on the basis of overall performance with respect to Enbridge and all of its affiliates and not solely based on performance with respect to us.

We are a partnership and not a corporation for United States federal income tax purposes, and therefore, are not subject to the executive compensation tax deductible limitations of Internal Revenue Code §162(m). In addition, we are not the employer for any of the NEOs.

The board of directors of Enbridge implemented an Incentive Compensation Clawback Policy that enables it to recover, from current and former executives, certain incentive compensation amounts that were awarded or paid to such individuals based upon the achievement of financial results that are subsequently materially restated or corrected, in whole or in part, if such individuals engaged in fraud or willful misconduct that resulted in the need for such restatement or correction and it is determined that the incentive compensation paid to the individuals would have been lower based on the restated or corrected results.

For a more detailed discussion of the compensation policies and philosophy of Enbridge, we refer you to a discussion of those items as set forth in the Executive Compensation section of the Enbridge Management Information Circular, or MIC, on the Enbridge website at www.enbridge.com. The Enbridge MIC is produced by Enbridge pursuant to Canadian securities regulations and is not incorporated into this document by reference or deemed furnished or filed by us under the Exchange Act. We refer to the MIC to provide our investors with an understanding of the compensation policies and philosophy of the ultimate parent of our General Partner.

Elements of Compensation

The HRC Committee sets the compensation philosophy of Enbridge, which is approved by the Enbridge board of directors. Enbridge has a pay-for-performance philosophy and programs that are designed to be aligned with its interests, on an enterprise-wide basis, as well as the interests of its shareholders. A significant portion of total direct compensation of Enbridge’s senior management is dependent on actual performance measured against short, medium and long-term performance goals of Enbridge, on an enterprise-wide basis, which are approved by the HRC Committee. As business units of Enbridge, we and EEP contribute to its overall growth, earnings and attainment of performance goals.

The elements of total compensation in 2016 for senior management of Enbridge, which includes Mr. Harper, are:

 

    Base Salary — to provide a fixed level of compensation for performing day-to-day responsibilities, while balancing the individual’s role and competency, market conditions and issues of attraction and retention.

 

    Short-term incentive — to provide a competitive, performance cash award based on pre-determined corporate, business unit and individual goals that measure the execution of the business strategy over a one-year period.

 

    Medium-term and long-term incentives — to recognize contributions and provide competitive, compensation comprised of performance stock units, restricted stock units, performance stock options and incentive stock options that are tied to the share price of Enbridge common shares, MEP common units and other financial measures, and are considered at-risk to motivate performance over the medium and long term.

 

    Pension plan — to provide a competitive retirement benefit.

 

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    Savings plan — to promote ownership of Enbridge common shares and to provide the opportunity to save additional funds for retirement or other financial goals.

 

    Perquisites — to provide a competitive allowance to offset expenses largely related to the executive’s role.

 

    Benefits — to provide a competitive benefits program including health and welfare, life insurance and disability programs.

 

    Employment agreements — to provide specific total compensation terms in situations of involuntary termination or constructive dismissal.

The elements of compensation for NEOs other than Mr. Harper are similar to those described above, except they are not eligible for Enbridge performance stock options. In addition, with the exception of Messrs. Harper and Kaitson, no other NEOs have employment agreements. The HRC Committee makes determinations as to whether the enterprise-wide performance goals have been achieved, approves business unit results and makes adjustments as necessary to more accurately reflect whether those goals have been met or exceeded. For example, the

HRC Committee may determine to disregard the impacts of certain long-term financing activities on cash flow when determining whether certain goals have been met.

Base Salary

Base salary for the NEOs reflects a balance of market conditions, role, individual competency and attraction and retention considerations and takes into account compensation practices at peer companies of Enbridge. Increases in base pay for all NEOs are based primarily on competitive considerations.

Short-Term Incentive Plan

The Enbridge short-term incentive plan, or STIP, is designed to provide incentive for and to reward, the achievement of goals that are aligned with the Enbridge annual business plan. The target short-term incentive reflects the level of responsibility associated with the role and competitive practice and is expressed as a percentage of base salary. Actual incentive awards can range from zero to two times the target. Awards under the plan are based on performance relative to goals achieved at the Enbridge corporate level, business unit level and individual level. Performance relative to goals in each of these areas is reflected on a scale of zero to two; zero indicates performance was below threshold levels, one indicates that goals were achieved and two indicates that performance was exceptional.

The following is a summary for 2016 of the incentive targets, payout range, and relative weightings between the Enbridge corporate, business unit and individual performance:

 

    Target
STIP% (1)
    Pay Out
Range
    Relative Weighting  
                Corporate     Business Unit     Individual  

C. Gregory Harper

    65     0 – 130     25     50     25

President (and Principal Executive Officer) and Director

         

Stephen J. Neyland

    35     0 – 70     25     50     25

Vice President — Finance (and Principal Financial Officer)

         

E. Chris Kaitson

    35     0 – 70     25     50     25

Vice President — Law & Assistant Corporate Secretary

         

Kerry C. Puckett

    35     0 – 70     25     50     25

Vice President — Engineering and Operations, Gathering & Processing

         

R. Poe Reed

    35     0 – 70     25     50     25

Vice President & Chief Commercial Officer

         

 

(1)  All values are expressed as percentages of base salary.

 

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The overall performance multiplier and STIP are calculated as follows:

 

Performance multiplier

  

STIP

Corporate target incentive opportunity x (0 – 2)

   Base Salary $

+ Business unit target incentive opportunity x (0 – 2)

   x Target STIP %

+ Individual target incentive opportunity x (0 –2)

   x Overall performance multiplier (0 –2)

 

  

 

= Overall performance multiplier (0 – 2)

   = $ Short term incentive award

Enbridge Corporate Performance

Corporate performance was measured by available cash flow from operations per share, or ACFFO, in 2016. This is a metric that provides enhanced transparency of Enbridge’s cash flow growth and increased comparability of results relative to peers and ensures full value recognition for Enbridge’s superior assets, growth and commercial arrangements.

The ACFFO metric represents a significant component of the named executives’ short-term incentive award at 25%. For incentive compensation purposes, Enbridge’s 2016 ACFFO payout range was $3.80 Canadian Dollars, or CAD, per share to $4.32 CAD per share, as approved by the Enbridge HRC Committee prior to the start of 2016. Adjustments are made to ensure the result is a fair reflection of performance, including adjustments for weather normalization, project development and transaction costs, realized inventory revaluation allowance, employee severance and restructuring costs, and other miscellaneous items. For incentive purposes, ACFFO also excludes the impact of certain long-term financing activities on cash flow. The corporate multiplier ranges from 0 to 2.0, with 1.0 meaning that the performance measure was met. To align with cost savings measures undertaken in 2016, the corporate multiplier was reduced by 0.05. The 2016 adjusted corporate STIP performance multiplier is 1.50.

Enbridge Business Unit Performance

Business unit performance measures vary among the NEOs to reflect the annual business plans and operations for which each NEO is accountable. Performance is measured against targets that are established at the beginning of the year. The business performance measure for each NEO is designed to reflect his multiple responsibilities at Enbridge. The weightings by unit for each NEO is calculated as follows:

 

Business Unit

   C. Gregory
Harper
    Stephen J.
Neyland
    E. Chris
Kaitson
    Kerry C.
Puckett
    R. Poe Reed  

Gas Pipelines and Processing — Midcoast Operating

     50         100     100

Gas Pipelines and Processing — Shared Services

       100     100    

Gas Pipelines and Processing — Canada & Joint Projects Canada & Joint Ventures

     50        

The detailed business unit performance measures which determine the business unit multipliers upon which the NEO’s STIP is calculated are included in the following tables. They reflect rounding and range from 0 to 2.0, with 1.0 meaning that the target performance measure was met. The business units include us, but also include

 

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portions of other Enbridge businesses. To align with cost savings measures undertaken in 2016, all business unit multipliers were reduced by 0.05.

 

Gas Pipelines & Processing — Midcoast Operating

Performance Measure

   Weight  

Sub Measures & Weightings

       Multiplier   Weighted
Multiplier

Safety, Operations & Integrity

   35%   Health and Safety Training    4%   1.77   0.62
     Safety Observations    4%    
     Incident Investigation Action Items    4%    
     Total Recordable Injury Frequency    8%    
     Operational Risk Assessment — Inspections    5%    
     Operational Risk Reduction — Safety Audit Items    4%    
     Process Safety Incident Frequency    6%    

Financial

   40%   Midcoast Distributable Cash Flow    25%   2.00   0.80
     Offshore Earnings before Interest and Taxes    15%    

Commercial

   20%   Midcoast 5 Year Cumulative EBITDA    10%   1.15   0.23
     Midcoast 2017 Minimum EBITDA    5%    
     Non-MOLP Capital Committed    5%    

Employee Development

   5%   Career Development Discussions    5%   2.00   0.10
    

Less: Management Adjustment

       0.05
    

Business Unit Performance Multiplier

       1.70

Gas Pipelines & Processing — Shared Services

Performance Measure

   Weight  

Sub Measures & Weightings

       Multiplier   Weighted
Multiplier

Safety, Operations & Integrity

   35%   Health and Safety Training    4%   1.77   0.62
     Safety Observations    4%    
     Incident Investigation Action Items    4%    
     Total Recordable Injury Frequency    8%    
     Operational Risk Assessment — Inspections    5%    
     Operational Risk Reduction — Safety Audit Items    4%    
     Process Safety Incident Frequency    6%    

Financial

   40%   US Liquids Earnings before Interest and Taxes    16%   1.90   0.76
     Midcoast Distributable Cash Flow    18%    
     Offshore EBIT Earnings before Interest and Taxes    6%    

Commercial

   20%   Midcoast 5 Year Cumulative EBITDA    10%   1.15   0.23
     Midcoast 2017 Minimum EBITDA    5%    
     Non-MOLP Capital Committed    5%    

Employee Development

   5%   Career Development Discussions    5%   2.00   0.10
    

Less: Management Adjustment

       0.05
    

Business Unit Performance Multiplier

       1.66

 

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Gas Pipelines & Processing — Canada & Joint Ventures

Performance Measure

   Weight  

Sub Measures & Weightings

       Multiplier   Weighted
Multiplier

Safety, Operations & Integrity

   35%   Health and Safety Training    4%   1.77   0.62
     Safety Observations    4%    
     Incident Investigation Action Items    4%    
     Total Recordable Injury Frequency    8%    
     Operational Risk Assessment — Inspections    5%    
     Operational Risk Reduction — Safety Audit Items    4%    
     Process Safety Incident Frequency    6%    

Financial

   35%   Canadian Midstream Earnings before Interest and Taxes    13%   2.00   0.70
     Alliance Earnings before Interest and Taxes    10%    
     Aux Sable Earnings before Interest and Taxes    7%    
     General & Administrative Costs    5%    

Commercial

   25%   Tupper Plants 2016 EBITDA    5%   0.64   0.16
     5 Year Cumulative EBITDA    10%    
     2017 Minimum EBITDA    10%    

Employee Development

   5%   Career Development Discussions    5%   2.00   0.10
    

Less: Management Adjustment

       0.05
    

Business Unit Performance Multiplier

       1.53

Individual Performance

Each of the NEOs establishes individual goals at the beginning of each year by which individual performance is measured. These goals are based on areas of strategic and operational emphasis related to their respective portfolios, development of succession candidates, employee engagement, community involvement and leadership. Individual performance ratings are recommended to the HRC Committee by the President & Chief Executive Officer of Enbridge for Mr. Harper. The individual performance ratings for the remaining NEOs are recommended by their supervisors to the Enbridge executive leadership team, including the President & Chief Executive Officer of Enbridge.

Summary of 2016 Performance Multipliers

The following table summarizes the corporate, business unit and individual performance multipliers for each NEO, associated weights and overall performance multiplier result:

 

NEO

   Corporate
Performance (a)
(Weight x Multiplier)
     Business Unit
Performance (b)
(Weight x Multiplier)
     Individual
Performance (c)
(Weight x Multiplier)
     Overall
Performance
Multiplier
(a+b+c)
 

C. Gregory Harper

     25% x 1.50 = 0.38        50% x 1.62 = 0.81        25% x 1.65 = 0.41        1.60  

Stephen J. Neyland

     25% x 1.50 = 0.38        50% x 1.66 = 0.83        25% x 1.65 = 0.41        1.62  

E. Chris Kaitson

     25% x 1.50 = 0.38        50% x 1.66 = 0.83        25% x 1.65 = 0.41        1.62  

Kerry C. Puckett

     25% x 1.50 = 0.38        50% x 1.70 = 0.85        25% x 1.85 = 0.46        1.69  

R. Poe Reed

     25% x 1.50 = 0.38        50% x 1.70 = 0.85        25% x 1.65 = 0.41        1.64  

 

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Based on the overall performance multiplier determined from the above table, short term incentive awards for our NEOs were calculated as follows:

 

NEO

   Base
Salary (a)
     Target (b)     Overall
Performance
Multiplier (c)
     Calculated
STIP (1)
=(a) x (b) x (c)
     Actual
STIP (1)
 

C. Gregory Harper

   $ 424,300        65     1.60      $ 441,272      $ 440,583  

Stephen J. Neyland

     270,144        35     1.62        153,172        192,937  

E. Chris Kaitson

     283,184        35     1.62        160,565        190,319  

Kerry C. Puckett

     295,000        35     1.69        174,493        174,236  

R. Poe Reed

     355,200        35     1.64        203,885        203,574  

 

(1)  Calculated and actual results may vary from mathematical results due to proration of changes to STIP targets throughout the year, rounding and/or discretionary adjustments.

The calculated STIP may be adjusted for Mr. Harper by a recommendation of the President & Chief Executive Officer of Enbridge to the HRC Committee, which must approve any such recommendation. Any adjustment for the remaining NEOs would be reviewed by the executive leadership team of Enbridge, including the President & Chief Executive Officer of Enbridge. Enbridge’s President & Chief Executive Officer approves the awards on an enterprise-wide basis.

Medium and Long-Term Incentives

Enbridge believes that a combination of medium and long-term incentive plans aligns a component of executive compensation with the interests of Enbridge shareholders beyond the current year. A significant percentage of the value of the annual long-term incentive awards to the NEOs is contingent on meeting performance criteria and price hurdles. Specifically, when targets and performance relative to peer organizations are achieved, the value of the medium and long-term incentive is maximized for the executives while also benefitting shareholders. The mix of medium and long-term incentive programs and total target medium and long-term incentive opportunity, expressed as a percentage of base salary, are as follows:

 

NEO

   Target Medium
& Long-term
Incentives
    Amount Each Plan Contributes to Total Target Grant  
           Enbridge
Performance
Stock Units
    MEP
Performance
Stock Units
    Enbridge
Performance
Stock Options (1)
    Enbridge
Incentive
Stock Options
 

C. Gregory Harper

     200.0     30.0     80.0     60.0     30.0

Stephen J. Neyland

     70.0     12.6     28.0     —         29.4

E. Chris Kaitson

     70.0     12.6     28.0     —         29.4

Kerry C. Puckett

     70.0     12.6     28.0     —         29.4

R. Poe Reed

     70.0     5.3     52.5     —         12.2

 

(1)  Performance stock options are granted approximately once every five years to Enbridge executive officers only, and they are intended to cover a five year period. The above table displays the intended annualized value. The last regular performance stock option grant was in 2012, which was intended to provide annual value over the period from 2012 to 2016; however, Mr. Harper was provided an initial grant of performance stock options upon his hire in 2014 to cover the period from 2014 to 2016.

With the exception of Mr. Harper, actual award values, expressed as a percentage of base salary, range between 0% and 180% of the target medium and long-term incentive opportunity, based on individual performance history, succession potential, retention considerations and market competitiveness. Discretionary adjustments may also be considered.

 

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Enbridge

Enbridge has four plans that make up its medium and long-term incentive program for our named executives:

 

    A Performance Stock Unit Plan (2007), or PSUP, which includes three-year phantom shares with performance conditions that impact payout;

 

    A Performance Stock Option Plan (2007), or PSOP, which includes eight-year options to acquire Enbridge common shares with performance and time vesting conditions;

 

    An Incentive Stock Option Plan (2007), or ISOP, which includes 10-year stock options to acquire Enbridge common shares with time vesting conditions; and

 

    A Restricted Stock Unit Plan (2006), or RSUP, which includes 35-month phantom shares with time vesting conditions.

Only the Enbridge Executive Leadership Team, which includes Mr. Harper, are eligible to receive grants under the PSOP.

In 2014 upon hire, Mr. Harper received a one-time discretionary restricted stock unit, or RSU, grant which includes 35-month phantom shares with time vesting conditions. This was a one-time grant outside of his normal targets of medium and long-term incentives. Mr. Harper is the only NEO who received an RSU grant.

MEP

MEP has an additional plan that makes up its medium and long-term incentive program for senior management, for which all NEOs are eligible:

 

    A Long-term Incentive Plan, or LTIP, which includes restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights with performance conditions that impact payout. Beginning in 2015, our General Partner issued performance stock units, or PSUs, under this plan.

Enbridge Plans

PSUP

The PSUP is a three-year performance-based unit plan. PSUs vest at the end of a three year performance period that begins on January 1 of the year granted and during the term the units are outstanding, a liability and expense are recorded by Enbridge based on the number of PSUs outstanding (including additional PSUs resulting from reinvesting dividends) and the current market price of an Enbridge common share with an assumed performance multiplier that is determined quarterly based on progress towards achieving the established performance criteria, until the end of the performance period at which point the performance multiplier is known. PSUs do not involve the issuance of any shares of common stock of Enbridge. Notional dividends are paid on the PSUs which are invested in additional PSUs at the then current market price for one share of Enbridge common stock, which are not included in the estimated future payout amounts for purposes of calculating grant date fair value, but have been included in the compensation associated with stock awards in the Summary Compensation Table.

The initial value of each of these PSUs on the grant date is equivalent to the volume weighted average closing price of one Enbridge common share as quoted on the TSX or NYSE for the 20 trading days immediately preceding the start of the performance period. Performance measures and targets are established at the start of the term to reflect levels of performance that would be considered weak, average or exceptional. Achievement of the performance targets can decrease or increase the final award value in a range of 0% to 200%. The target level at which PSUs are issued represents 100% of the number of PSUs initially granted and attainment of the established

 

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performance criteria. Payments under the PSUP may be increased up to 200% of the original award when Enbridge exceeds the established targets. If Enbridge fails to meet threshold performance levels, no payments are made under the PSUP. Awards are granted annually and paid in cash at the end of a three-year term based on two performance criteria that were established for the grant: For the 2016 grant, these measures are ACFFO growth and relative risk-adjusted total shareholder return, or risk-adjusted TSR, each of which are weighted at 50%. For the 2015 and 2014 grants, the performance measures were EPS and relative price to earnings ratio, or P/E Ratio, each of which were weighted at 50%.

ACFFO growth is a measure that represents a commitment to Enbridge shareholders to achieve operating cash flow growth that meets or exceeds the average industry rates forecast at the time of grant, demonstrate ability to deliver on its growth plan and continue dividend increases. The ACFFO growth required to achieve a two multiplier (the maximum) would demonstrate achievement of compound annual growth consistent with exceptional industry growth rate and would represent exceptional performance to the investment community.

Risk-adjusted TSR is total shareholder return divided by volatility over the measurement period and is used to compare Enbridge against its performance peers. Enbridge strongly believes risk-adjusted TSR resonates with the investor value proposition of strong, consistent total returns over the long term. Performance below the 25 th percentile results in a multiplier of zero, performance at the median results in a multiplier of one, and performance above the 75 th percentile results in a multiplier of two. Multipliers for performance between these anchors will be determined through linear interpolation. The following table presents the comparative group for risk-adjusted TSR for the 2016 grant:

Risk-adjusted TSR — Comparative Group of Companies

 

Canadian Utilities Limited    NiSource Inc.
Dominion Resources    ONEOK, Inc.
DTE Energy Company    Pembina Pipeline Corporation
Energy Transfer Equity    PG&E Corporation
Enterprise Products Partners, L.P.    Plains All American Pipeline, L.P.
Fortis Inc.    Sempra Energy
Inter Pipeline Ltd.    Spectra Energy Corp.
Kinder Morgan, Inc.    TransCanada Corporation
Magellan Midstream Partners, L.P.    Williams Companies, Inc.

This peer group of companies was selected because they are all capital market competitors of Enbridge, have a similar risk profile and are in a comparable sector. The peer group used to measure relative risk-adjusted TSR is reviewed annually. The 2016 peer group was amended to remove those no longer applicable due to acquisition or restructuring.

PSOP

Performance stock options align the Enbridge executive leadership team, including Mr. Harper, with its shareholders by tying vesting to the achievement of defined performance criteria. Once the performance hurdles are met, exercisability is subject to time requirements. Enbridge grants performance stock options to its executives approximately every five years with eight year terms that become exercisable over a period of five years at a rate of 20% per year provided the performance criteria are met. The approach used to determine the common share price hurdles was determined from the Enbridge long-range plan which is integrated with the strategic growth plans of Enbridge and historic industry P/E Ratio information.

Enbridge granted performance stock options to Mr. Harper in 2014 in conjunction with his employment with Enbridge to cover the period from 2014 to 2016. Mr. Harper is the only NEO who participated in this plan.

 

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The performance criteria for Mr. Harper’s 2014 performance stock options vest in equal annual installments over four years (normally over five years), subject to Enbridge common share price hurdles of $53.00 CAD and $58.00 CAD on the Toronto Stock Exchange, or TSX, weighted at 60% and 40%, respectively, which must be met by February 2019. As of December 31, 2016, both of the Enbridge common share price targets for the 2014 grant have been met, therefore 50% of the grant is exercisable. For clarity, the following table further describes the vesting provisions and performance criteria of Mr. Harper’s 2014 performance stock option grant:

 

     % Vested  

Share price (1)

   Year 1 (25%
time vested)
    Year 2 (50%
time vested)
    Year 3 (75%
time vested)
    Year 4 (100%
time vested)
 

Less than $53 (0% performance vested)

     0 %     0 %     0 %     0 %

Greater than $53 but less than $58 (60% performance vested)

     15 %     30 %     45 %     60 %

Greater than $58 (100% performance vested)

     25 %     50 %     75 %     100 %

 

Attribution

   Year 1    Year 2    Year 3    Year 4

Intended annual value

   33% of

grant value

   33% of

grant value

   34% of

grant value

   0% of
grant value

 

(1)  The weighted average trading price in CAD over a period of 20 consecutive trading days. The grant price was $48.81 CAD.

ISOP

The ISOP provides regular stock options that focus the Enbridge executives on increasing shareholder value over the long-term through common share price appreciation. Stock options are granted annually to Enbridge executives entitling them to acquire Enbridge common shares at a price defined at the time of grant. These options become exercisable over a period of four years at a rate of 25% per year, and the term of each grant is ten years.

If an option is awarded at a time when a blackout period is in effect, the grant price and grant date of the option will be set on the sixth trading day following the termination of the blackout period, and will not be less than 100% the fair market value as of grant date (the weighted average trading price of an Enbridge common share on the NYSE for the five trading days immediately preceding grant date.) During 2016, each of the NEOs received grants of Enbridge incentive stock options where one option is equivalent to one share of Enbridge common stock.

RSUP

The RSUP is a plan that awards RSUs which have the same value as a common share of Enbridge stock, but are not traded in external financial markets. Throughout the term, units are added to the grants as if dividends were received and reinvested into additional units based on the actual dividend rate for common shares of Enbridge stock. At the end of the 35-month term, the units are paid in cash based on the weighted average price of an Enbridge common share on the NYSE for 20 trading days prior to the end of the term. Due to a one-time RSU grant made upon hire, Mr. Harper is the only NEO that participates in this plan.

LTIP

In 2015 and 2016, under the LTIP, our General Partner issued PSUs tied to our publicly traded Class A common units, similar to Enbridge’s PSUP. Performance measures and targets are established at the start of the term to reflect levels of performance that would be considered weak, average or exceptional. The provisions

 

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governing our PSUs are consistent with those of Enbridge PSUs with the exception of the performance measures used. Achievement of the performance targets can decrease or increase the final award value in a range of 0% to 200%. Our PSUs do not involve the issuance of any of our units. Throughout the term, units are added to the grants as if cash distributions were received and reinvested into additional units based on the actual cash distribution rate for our units. Awards are granted annually and paid in cash at the end of a three-year term based on two performance criteria that were established for the grant: for the 2016 grant, these measures are distributable cash flow per unit (DCF) growth and reduction in relative yield (Yield Ratio), each of which are weighted at 50%.

The DCF performance reflects our commitment to our unitholders to achieve DCF growth that meets or exceeds average industry growth rates projected at the time of grant. DCF represents the cash we have available for distribution to unitholders, and is a key metric for master limited partnerships. The DCF required to achieve a two multiplier (the maximum) would demonstrate achievement of compound annual growth consistent with exceptional industry growth rate and would represent exceptional performance to the investment community.

The second performance criterion is the Yield Ratio, which is a measure of how effective we are at deploying capital and growing cashflow and the underlying business relative to a selected comparative group of companies. A reduction in yield, relative to peers, represents improvement in both areas. The following table presents the comparative group for the Yield Ratio for the 2016 grant:

Yield Ratio — Comparative Group of Companies

 

Arc Logistics Partners, L.P.    Global Partners, L.P.
American Midstream Partners, L.P.    Martin Midstream Partners, L.P.
Azure Midstream Partners, L.P.    Rose Rock Midstream Partners, L.P.
Crestwood Midstream Partners, L.P.    Southcross Energy Partners, L.P.
DCP Midstream Partners, L.P.    Summit Midstream Partners, L.P.
Enable Midstream Partners, L.P.    Targa Resources Partners, L.P.
EnLink Midstream Partners, L.P.   

This peer group of companies was selected because they are all U.S. gas gathering and processing MLPs whose strategies involve organic growth or drop-downs from general partners, similar to us. The peer group used to measure yield ratio is reviewed annually. The 2016 peer group was amended to remove those no longer applicable due to acquisition or restructuring.

The board of directors of our General Partner has the authority to approve any amendments to the performance measures, the expected levels of performance and term. Additionally, the board of directors of our General Partner has the authority to waive restrictions with respect to participation in the LTIP or the maturity of grants under the LTIP for any specific participants.

Due to a material deterioration in market fundamentals, and in consideration for the fact that the majority of peers in the MEP performance stock unit plan provide restricted stock units instead of performance stock units within their plans, a minimum payout of 0.5x was established. This minimum payout is applicable only to the 2016 grant.

On January 27, 2017, we announced that we had entered into a merger agreement with EECI, whereby EECI will acquire all of our outstanding common units not already held by EECI, EEP or their affiliates. As a result of the merger, other than grants previously provided in 2016 and 2015, no further grants under the LTIP will be made.

 

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Service Agreements and Allocation of Compensation to the Partnership

EEP provides managerial, administrative, operational and director services to us pursuant to the intercorporate services agreement, which services are ultimately provided through service agreements among EEP, Enbridge Management and Enbridge and its affiliates. Pursuant to the intercorporate services agreement, we reimburse EEP for our allocated portion of the costs of such services. Through a services agreement between our General Partner and EEP, we are charged for the services of executive management resident in the United States, including all of the NEOs.

EEP determines a budgeted allocation rate for our NEOs’ compensation in accordance with the terms of the agreements it has entered into with Enbridge Management, Enbridge and its affiliates and provides reimbursement for costs of services based on an allocation method provided under those agreements. Since the allocation rate is estimated, the actual time spent by an NEO on behalf of EEP (which includes services to us) may vary from the budgeted allocation rate, and EEP may be allocated more or less of that NEO’s compensation than the actual percentage of his time spent on its behalf in a given year. The amount of our NEOs’ compensation that is allocated by EEP to us is determined in accordance with the terms of the intercorporate services agreement. For additional information, regarding our intercorporate services agreement, please read Item 13. Certain Relationships and Related Transactions, and Director Independence — Intercorporate Service Agreements.

The compensation of our NEOs included in the tables below is established by Enbridge as described above. We selected our three most highly compensated executives (other than our principal executive officer and our principal financial officer) based on current estimates regarding the amount of time such executives devoted to us. We have included in the following tables the full amount of compensation and related benefits provided for each of the NEOs together with an estimate of the approximate time spent by each NEO on MEP’s behalf and the estimated amount of compensation cost allocated to MEP for the years ended December 31, 2016, 2015 and 2014, as applicable. Since the amount of NEO compensation allocated to us is based on estimates of time spent on our behalf by the particular NEO, the compensation amounts allocated to us as presented below may not reflect the actual amount of compensation allocated to us for each particular NEO.

 

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SUMMARY COMPENSATION TABLE

 

Name and Principal
Position

(a)

  Year
(b)
    Salary
($)
(c)
    Bonus
($)
(d)
    Stock
Awards (1)
($)

(e)
    Option
Awards (2)
($)

(f)
    Non-Equity
Incentive

Plan
Compensation (3)
($)

(g)
    Change in
Pension

Value and
Nonqualified
Deferred
Compensation
Earnings

($)
(h)
    All Other
Compensation (4)
($)

(i)
    Total
($)
(j)
    Approximate
Percentage
of Time
Devoted to
Midcoast
Energy
Partners,
L.P.

(%)
    Approximate
Amount
Allocated to
Midcoast
Energy
Partners,
L.P.

($)
 

C. Gregory Harper (5)

    2016       424,300       —         916,722       326,777       440,583       204,000       113,950       2,426,332       35       849,216  

President (Principal

    2015       421,725       —         279,908       264,991       359,594       130,000       118,886       1,575,104       35       551,286  

Executive Officer)

and Director

    2014       377,167       370,000       471,315       197,841       273,254       119,000       49,792       1,858,369       45       836,266  

Stephen J. Neyland

    2016       270,144       —         246,260       216,012       192,937       193,000       35,001       1,153,354       40       461,341  

Vice President —

    2015       268,497       —         99,320       225,871       127,881       11,000       38,040       770,609       45       346,774  

Finance (Principal

Financial Officer)

    2014       260,718       —         384,811       238,549       122,234       523,000       38,175       1,567,487       45       705,369  

E. Chris Kaitson (6)

    2016       283,184       —         195,161       156,626       190,319       223,000       35,263       1,083,553       60       650,132  

Vice President —

                     

Law & Assistant

Corporate Secretary

                     

Kerry C. Puckett

    2016       290,370       —         249,891       197,096       174,236       251,000       35,263       1,197,856       85       1,018,178  

Vice President —

    2015       280,156       —         101,594       204,510       153,118       19,000       43,815       802,193       85       681,864  

Engineering and

Operations Gathering

& Processing

    2014       266,230       —         331,638       219,609       113,857       398,000       51,942       1,381,276       85       1,174,084  

R. Poe Reed (6)

    2016       355,200       —         92,329       16,087       203,574       139,000     35,950       842,140       100     842,140  

Vice President &

                     

Chief Commercial

Officer

                     

 

(1)  The compensation expense is associated with PSUs granted on January 1 in 2016, 2015 and 2014 under the PSUP and PSUs granted on January 1 in 2016 and 2015 under the LTIP for each NEO and RSUs, awarded in January 2014, with respect to Mr. Harper, that are reflected in this column represent one-third of the market value for each year the PSUs and RSUs are outstanding. The PSUs are measured based on the number of respective units granted, dividends reinvested, cliff-vested, the actual or forecast performance multiplier (RSUs do not have performance multipliers used in determining the payout amount). PSUs and RSUs are priced at the date of grant revalued each quarter using the 20 day weighted average share price preceding the last day of the quarter. For example, 2016 includes one-third of the market values for PSUs issued in 2016, 2015 2014 under the PSUP, one-third of the market values for PSUs issued in 2016 and 2015 under the LTIP and one-third of the market values for RSUs issued in 2014. In 2016, the compensation expense recorded for PSUs granted in 2016, 2015 and 2014 include performance multipliers for years 2016 through 2014, which are estimated based upon the expected or achieved levels of performance in relation to established targets for each year. For years prior to the year a payout is made, a performance multiplier is forecast based upon the progress made in attaining the established performance criteria unless the actual multiplier has been determined. Refer also to Medium and Long-Term Incentives for additional discussion regarding the PSUs. The grant date fair value for each PSU and RSU grant represents the weighted average closing price of an Enbridge common share as quoted on the NYSE for the 20 consecutive days prior to the grant date of January 1 each year. RSUs were granted at a grant price of $41.65 in 2014. Compensation expense as reported in the Summary Compensation Table above for Stock Awards has been determined using the following assumptions:

 

PSU/RSU Grant Date Fair Market Value Prices

   2016      2015      2014  

Enbridge (20-day average before January 1 of listed year) USD (NYSE)

   $ 31.85      $ 49.87      $ 41.65  

MEP (20-day average before January 1 of listed year) USD (NYSE)

   $ 7.98      $ 14.10        N/A  

 

Revaluation Date

   Mar-31      Jun-30      Sep-30      Dec-31  

2014 – 2016 EI Grants

           

20-day volume weighted average USD (NYSE)

   $ 37.19      $ 41.54      $ 43.65      $ 42.24  

2014 PSUs assumed performance multiplier

     1.77        1.77        1.77        1.77  

2015 PSUs assumed performance multiplier

     2.00        2.00        2.00        2.00  

2016 PSUs assumed performance multiplier

     1.50        1.50        1.50        1.50  

2015 – 2016 MEP Grants

           

20-day volume weighted average USD (NYSE)

   $ 4.41      $ 8.67      $ 8.67      $ 6.88  

2015 PSUs assumed performance multiplier

     1.00        1.00        1.00        0.25  

2016 PSUs assumed performance multiplier

     1.00        1.00        1.00        1.25  

 

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(2)  Under the authoritative accounting provisions for share-based payments, the annual expenses for option awards that are granted under the Enbridge ISOP and PSOP are determined by computing the fair value of the options on the grant date using the Black-Scholes option pricing model. The following assumptions were used in computing the fair value of the options on the grant date for the respective option pricing model employed and the indicated year:

 

     ISOP (a)     PSOP (b)  

Assumption

   2016     2015     2014     2016      2015      2014  

Expected option term in years

     6       6       6       N/A        N/A        6.5  

Expected volatility

     28.17 %     22.36 %     20.07 %     N/A        N/A        15.00 %

Expected dividend yield

     4.44 %     3.20 %     2.87 %     N/A        N/A        2.80 %

Risk-free interest rate

     1.55 %     1.81 %     1.90 %     N/A        N/A        1.70 %

 

  (a) All ISOs were granted in $USD.
  (b) All PSOs were granted in $CAD.

The fair value of options granted as computed using the above assumptions is expensed over the shorter of the vesting period for the options and the period to early retirement eligibility. The exercise price and fair value information for all option grants have been converted to USD as set forth in the table below:

 

     ISOP      PSOP  
     2016      2015      2014      2016      2015      2014 (a)  

Exercise price in CAD (TSX)

     N/A        N/A        N/A        N/A        N/A      $ 48.81  

Grant date exchange rate for $1 USD

     N/A        N/A        N/A        N/A        N/A      $ 1.1057  

Exercise price in USD (NYSE)

   $ 32.56      $ 47.41      $ 44.09        N/A        N/A      $ 44.14  

Vesting period in years

     4        4        4        N/A        N/A        4  

Option fair value on grant date in CAD

     N/A        N/A        N/A        N/A        N/A      $ 5.77  

Option fair value on grant date in USD

   $ 6.92      $ 7.10      $ 6.68        N/A        N/A      $ 5.22  

Average year outstanding exchange rate for $1 USD

     N/A        N/A        N/A        N/A        N/A      $ 1.1055  

 

  (a) Prices shown in USD for the PSOs granted on March 13, 2014 in CAD are converted to USD using the exchange rates detailed above.

 

(3)  Non-equity incentive plan compensation represents awards that are paid in February of each year for amounts that are earned in the immediately preceding fiscal year under the Enbridge STIP as discussed in the above Compensation Discussion and Analysis.
(4)  The table which follows labeled “All Other Compensation” sets forth the elements comprising the amounts presented in this column.
(5)  Mr. Harper was elected as an officer of Enbridge Management and EEP’s General Partner in April 2014. Mr. Harper is also an executive officer of Enbridge with responsibility for other affiliates of Enbridge in addition to those for EEP’s General Partner and Enbridge Management. For more information, please see Part III, Item 10. Directors, Executive Officers and Corporate Governance.
(6)  Compensation is provided for each year in which the individual was a NEO. Messrs. Kaitson and Reed were not NEOs for the years ended December 31, 2015 and 2014.

ALL OTHER COMPENSATION (For the years ended December 31, 2016, 2015 and 2014)

 

Name

   Year      Flexible
Benefits (1)
$
     401(k)
Matching
Contributions (2)
$
     Other
Benefits (3)
$
     Total  

C. Gregory Harper

    

2016
2015
2014


 
    

35,000
35,000
32,219


 
    

13,250
13,250
13,000


 
    

65,700
70,636
4,573


 
    

113,950
118,886
49,792


 

Stephen J. Neyland

    

2016
2015
2014


 
    

20,000
20,000
20,000


 
    

12,988
13,250
13,000


 
    

2,013
4,790
5,175


    

35,001
38,040
38,175


 

E. Chris Kaitson (4)

     2016        20,000        13,250        2,013        35,263  

Kerry C. Puckett

    

2016
2015
2014


 
    

20,000
20,000
20,000


 
    

13,250
13,250
13,000


 
    

2,013
10,565
18,942


    

35,263
43,815
51,942


 

R. Poe Reed (4)

     2016        20,000        13,250        2,700        35,950  

 

(1)  Flexible benefits for our NEOs represent a perquisite allowance that is paid in cash as additional compensation.

 

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(2)  Our NEOs that participate in the Enbridge Employee Services, Inc. Savings Plan, referred to as the 401(k) Plan, may contribute up to 50% of their base salary, which is matched up to 5% by Enbridge. Both individual and matching contributions are subject to limits established by the Internal Revenue Service. Enbridge contributions are used to purchase Enbridge common shares at market value and employee contributions may be used to purchase Enbridge common shares or 21 designated funds.
(3)  Other benefits include parking, relocation, fitness, health assessment, financial planning, awards and vacation not taken and paid out in cash for the NEOs. Mr. Harper’s 2016 and 2015 amounts also include a cash award of $63,000 to partially replace the value lost from long-term incentives of his former employer.
(4)  Compensation is provided for each year in which the individual was a NEO. Messrs. Kaitson and Reed were not NEOs for the years ended December 31, 2015 and 2014.

The PSUs are granted to the NEOs pursuant to the PSUP and LTIP. The RSUs are granted pursuant to the RSUP and stock options are granted pursuant to the ISOP and the PSOP. Awards under these plans provide long-term incentive and are administered by the HRC Committee of Enbridge. Although stock options remain outstanding that were granted under the Enbridge Incentive Stock Option Plan (2002), no further stock options will be granted under this plan. The PSUs, RSUs and stock option granted in 2014 through 2016 to our NEOs are denominated in USD. The PSO grant to Mr. Harper is denominated in CAD. The three tables which follow set forth information concerning PSUs, RSUs and stock options granted during the year ended December 31, 2016, outstanding at December 31, 2016 and the number of awards vested and exercised during the year ended December 31, 2016 by each of the NEOs.

GRANTS OF PLAN-BASED AWARDS

 

Name
(a)

  Plan
Name
(b)
  Approval Date
(b)
  Grant Date
(b)
  Estimated Future Payouts
Under Non-Equity Incentive
Plan Awards (1)
    Estimated Future Payouts
Under Equity Incentive
Plan Awards (2)
    All Other
Option
Awards:
Number of
Securities
Underlying
Options (3)
(#)
(j)
    Exercise or
Base Price
of Option
Awards (3)
($/Sh)
(k)
    Grant Date
Fair Value
of Stock and
Option
Awards (3)
($)
(l)
 
                Threshold
($)
(c)
    Target
($)
(d)
    Maximum
($)
(e)
    Threshold
(#)
(f)
    Target
(#)
(g)
    Maximum
(#)
(h)
                   

C. Gregory Harper

  PSUP
LTIP
ISOP
STIP
  18-Feb-16
19-Feb-16
18-Feb-16
1-Feb-17
  1-Jan-16
1-Jan-16
29-Feb-16
24-Feb-17
   


—  
—  
—  
—  



 
   


—  
—  
—  
275,795



 
   


—  
—  
—  
551,590



 
   


—  
—  
—  
—  



 
   


6,360
55,070
—  
—  



 
   


12,720
110,140
—  
—  



 
   


—  
—  
38,980
—  



 
   


—  
—  
32.56
—  



 
   


202,566
439,459
269,742
—  



 

Stephen J. Neyland

  PSUP
LTIP
ISOP
STIP
  18-Feb-16
19-Feb-16
18-Feb-16
1-Feb-17
  1-Jan-16
1-Jan-16
29-Feb-16
24-Feb-17
   


—  
—  
—  
—  



 
   


—  
—  
—  
94,550



 
   


—  
—  
—  
189,101



 
   


—  
—  
—  


 
   


2,160
17,060
—  
—  



 
   


4,320
34,120
—  
—  



 
   


—  
—  
29,350
—  



 
   


—  
—  
32.56
—  



 
   


68,796
136,139
203,102
—  



 

E. Chris Kaitson

  PSUP
LTIP
ISOP
STIP
  18-Feb-16
19-Feb-16
18-Feb-16
1-Feb-17
  1-Jan-16
1-Jan-16
29-Feb-16
24-Feb-17
   


—  
—  
—  
—  



 
   


—  
—  
—  
99,114



 
   


—  
—  
—  
198,229



 
   


—  
—  
—  
—  



 
   


1,720
13,120
—  
—  



 
   


3,440
26,240
—  
—  



 
   


—  
—  
22,970
—  



 
   


—  
—  
32.56
—  



 
   


54,782
104,698
158,952
—  



 

Kerry C. Puckett

  PSUP
LTIP
ISOP
STIP
  18-Feb-16
19-Feb-16
18-Feb-16
1-Feb-17
  1-Jan-16
1-Jan-16
29-Feb-16
24-Feb-17
   


—  
—  
—  
—  



 
   


—  
—  
—  
103,250



 
   


—  
—  
—  
206,500



 
   


—  
—  
—  
—  



 
   


2,250
17,800

—  
—  




 

   


4,500
35,600
—  
—  



 
   


—  
—  
30,540
—  



 
   


—  
—  
32.56
—  



 
   


71,663
142,044
211,337
—  



 

R. Poe Reed

  PSUP
LTIP
ISOP
STIP
  18-Feb-16
19-Feb-16
18-Feb-16
1-Feb-17
  1-Jan-16
1-Jan-16
29-Feb-16
24-Feb-17
   


—  
—  
—  
—  



 
   


—  
—  
—  
124,320



 
   


—  
—  
—  
248,640



 
   


—  
—  
—  
—  



 
   


770
30,850
—  
—  



 
   


1,540
61,700
—  
—  



 
   


—  
—  
11,070
—  



 
   


—  
—  
32.56
—  



 
   


24,525
246,183
76,604
—  



 

 

(1) The estimated future payouts under non-equity incentive award plans represent awards under the Enbridge STIP as presented above in the Compensation Discussion and Analysis under the section labeled Short-Term Incentive Plan.
(2)  The grant date fair value for each PSU granted under the PSUP to each of our U.S.-based NEOs in 2016 was $31.85 USD, representing the volume weighted average closing price of one Enbridge common share as quoted on the NYSE for the 20 trading days immediately preceding the start of the performance period that began on January 1, 2016. The grant date fair value for each PSU granted under the LTIP in 2016 was $7.98 USD, representing the volume weighted average closing price of one MEP common unit as quoted on the NYSE for the 20 trading days immediately preceding the start of the performance period that began on January 1, 2016.

 

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(3)  The amounts included as the grant date fair value for the 2016 incentive stock option awards represent the amount determined by computing the fair value of the options in accordance with the authoritative guidance for share-based payments on the grant date using the Black-Sholes option pricing model with the following assumptions:

 

    6 years expected term;

 

    28.17% expected volatility;

 

    4.44% expected dividend yield; and

 

    1.55% risk free interest rate

The fair value of options granted as computed using these assumptions is $6.92 USD. The grant date fair value is expensed over the shorter of the vesting period for the options, generally four years, and in the year granted for employees age 55 and over and eligible for early retirement. The exercise price of the incentive stock options at the time of grant was $32.56 USD for our NEOs.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END

 

    Option Awards   Stock Awards

Name
(a)

  Number of
Securities
Underlying
Unexercised
Options
(#)
Exercisable
(b)
    Number of
Securities
Underlying
Unexercised
Options
(#)
Unexercisable (1)
(c)
    Option
Exercise
Price (2)
($)
(e)
    Option
Expiration
Date (1)
(f)
  Equity Incentive
Plan Awards:
Number of
Unearned Shares,
Units or Other
Rights That
Have Not Vested (4)
(#)
(i)
    Equity Incentive
Plan Awards:
Market or Payout
Value of Unearned
Shares, Units or
Other Rights That
Have Not Vested
($)
(j)
    Unit
Maturity
Date

C. Gregory Harper

   


—  
4,525
17,325
—  
 
 
 
 
   


38,980
13,575
17,325
69,040
 
 
 
 (3) 
   


32.56
47.41
44.09
44.13
 
 
 
 (3) 
  1-Mar-26
2-Mar-25
13-Mar-24
15-Aug-20
   


6,632
67,065

2,689
31,973

 
 (5)  

 
 (5) 

   


280,156
461,406
113,564
219,976
 
 
 
 
  31-Dec-18
31-Dec-18
31-Dec-17
31-Dec-17

Stephen J. Neyland

   






—  
6,158
18,150
30,788
39,100
33,450
7,700
2,750
 
 
 
 
 
 
 
 
   




29,350
18,472
18,150
10,262
—  

—  

—  

—  

 
 
 
 
 

 

 

 

   






32.56
47.41
44.09
43.84
38.65
28.99
21.97
15.80
 
 
 
 
 
 
 
 
  1-Mar-26
2-Mar-25
13-Mar-24
27-Feb-23
2-Mar-22
14-Feb-21
16-Feb-20
   


2,253
20,776

1,825
13,897

 
 (5)  

 
 (5) 

   


95,147
142,938
77,078

95,613

 
 
 

 

  31-Dec-18
31-Dec-18
31-Dec-17
31-Dec-17

E. Chris Kaitson

   







—  
4,883
11,625
22,163
28,700
35,800
13,200
27,000
27,000
 
 
 
 
 
 
 
 
 
   




22,970
14,647
11,625
7,387
—  

—  

—  

—  

—  

 
 
 
 
 

 

 

 

 

   







32.56
47.41
44.09
43.84
38.65
28.99
21.97
15.80
20.17
 
 
 
 
 
 
 
 
 
  1-Mar-26
2-Mar-25
13-Mar-24
27-Feb-23
2-Mar-22
14-Feb-21
16-Feb-20
25-Feb-19
19-Feb-18
   


1,794
15,978

1,501
10,685

 
 (5)  

 
 (5) 

   


75,766
109,926
63,395

73,513

 
 
 

 

  31-Dec-18
31-Dec-18
31-Dec-17
31-Dec-17

Kerry C. Puckett

   





—  
6,395
14,675
27,938
35,800
44,600
11,900
 
 
 
 
 
 
 
   




30,540
19,185
14,675
9,312
—  

—  

—  

 
 
 
 
 

 

 

   





32.56
47.41
44.09
43.84
38.65
28.99
21.97
 
 
 
 
 
 
 
  1-Mar-26
2-Mar-25
13-Mar-24
27-Feb-23
2-Mar-22
14-Feb-21
16-Feb-20
   


2,346
21,677

1,879
14,496

 
 (5)  

 
 (5) 

   



99,112

149,138
79,358
99,734

 

 
 
 

  31-Dec-18
31-Dec-18
31-Dec-17
31-Dec-17

R. Poe Reed

    —         11,070       32.56     1-Mar-26    

803
37,569

21,357

 
 (5)  

 (5) 

   

33,918
258,478
146,937
 
 
 
  31-Dec-18
31-Dec-18
31-Dec-17

 

(1)  Each ISO award has a 10-year term and vests pro-rata as to one fourth of the option award beginning on the first anniversary of the grant date; thus the vesting dates for each of the option awards in this table can be calculated accordingly. As an example, for Mr. Neyland’s grant that expires on February 27, 2023, the grant date would be 10 years prior or February 27, 2013 and as a result, the remaining unexercisable amounts would become fully vested on February 27, 2017 representing four years following the grant date.
(2) Where appropriate, all exercise prices and valuation prices prior to 2011 have been adjusted for the April 2011 Partnership stock split and Enbridge’s May 2011 stock split.

 

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(3) PSOs were provided to Mr. Harper on March 13, 2014, and are similar to the incentive stock options, except that the quantities that become exercisable are subject to both time and performance requirements. PSOs are granted on an infrequent basis and provide the eligible NEO the opportunity to acquire one Enbridge common share for each option held when the specified time and performance conditions are met. Upon the performance hurdles being met, the PSOs are also time vested 25% annually over four years. As of December 31, 2016, both Enbridge common share price targets had been met and 50% of the grant is exercisable. The PSOs denominated in CAD have been converted to USD using the exchange rate on the grant date of $48.81 CAD based on the TSX converted to $44.14 USD at the conversion rate of $1.1057 CAD to $1.00 USD.
(4)  The unearned common shares, units or other rights that have not vested under stock awards represent PSUs that have not yet reached the end of their term. The PSUs become vested upon achieving the established performance criteria discussed in Medium and Long-Term Incentives, at the end of the term. The amounts represented in the column are the number of units that have not vested at the 20-day volume weighted-average preceding December 31, 2016 of one Enbridge common share on the NYSE at $42.24 or one MEP common unit on the NYSE at $6.88. The market or payout values presented assume a performance multiplier of 1.00 for PSUs granted under the PSUP in 2016, 2015 and 2014 and PSUs granted under the LTIP in 2016, which represents the target level.
(5)  These amounts represent stock awards granted under the LTIP.

OPTION EXERCISES AND STOCK VESTED

 

Name
(a)

   Option Awards      Stock Awards  
     Number of
Shares Acquired
on Exercise
(#)
(b)
     Value Realized
on Exercise
($)
(c)
     Number of
Shares Acquired
on Vesting (1)
(#)
(d)
    Value Realized
on Vesting (2)
($)
(e)
 

C. Gregory Harper

     69,040        360,205        21,192  (3)      1,124,320  (3) 

Stephen J. Neyland

     —          —          2,774       216,755  

E. Chris Kaitson

     25,000        419,284        2,164       169,069  

Kerry C. Puckett

     11,900        237,922        2,718       212,420  

R. Poe Reed

     —          —          —         —    

 

(1)  The number of common shares acquired on vesting for stock awards represents the number of PSUs issued in 2014 and the related dividends paid that were used to acquire additional PSUs, all of which matured on December 31, 2016. No common shares are issued with respect to the PSUs that become vested; rather, cash is paid in an amount based on the value of an Enbridge common share at the maturity date and the level of achievement of the established performance goals. The payout for the PSUs granted in 2014 is expected to occur on or about March 10, 2017.
(2)  The value realized on vesting is determined based on the 20-day volume weighted-average preceding December 31, 2016 value of an Enbridge common share of $42.24 USD. In each case the common share price is multiplied by an estimated 1.85 performance factor multiplied by the number of PSUs for the PSUs that matured on December 31, 2016.
(3)  Includes RSUs which were granted to Mr. Harper in January 2014 and vested on December 31, 2016. The value realized on vesting is $41.82 USD, which is based on the 20-day volume weighted-average price for the period preceding December 1, 2016. The common share price is multiplied by the number of RSUs; there is no performance factor applicable to RSUs.

Pension Plan

Enbridge sponsors two qualified pension plans, the Retirement Plan for the Employees of Enbridge Inc. and its Canadian affiliates, or EI RPP, and the Enbridge Employee Services, Inc. Employees’ Pension Plan, or QPP. These pension plans provide defined benefits, and cover employees in Canada and the United States, respectively. Both plans are non-contributory. Enbridge also sponsors supplemental nonqualified retirement plans in both Canada, referred to as EI SPP, and the United States, referred to as US SPP, which provide defined benefits for the NEOs in excess of the tax-qualified plans’ limits. We collectively refer to the EI RPP, the QPP, the EI SPP and the US SPP as the Pension Plans. Defined benefits under the grandfathered benefit of the Pension

 

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Table of Contents

Plans are based on the employees’ years of service and average final remuneration with an offset for Social Security benefits, while cash balance benefits provide annual pay and interest credits to notional member accounts.

For service prior to becoming a senior management employee, there are different pension benefits depending on an employee’s hire date with Enbridge. Employees hired before January 1, 2002 have grandfathered benefits equal to: (a) 1.6% of the average of the participant’s highest average annual salary multiplied by (b) the number of credited years of service. Other provisions are aligned with the senior management provisions described below. For employees hired after January 1, 2002, the Pension Plans provide cash balance benefits with pay credits ranging from 4% to 10% depending on the employees’ pensionable pay, age and years of service.

For service while a senior management employee, the Pension Plans provide a yearly pension payable in the normal form (60% joint and survivor) equal to: (a) 2% of the sum of (i) the average of the participant’s highest annual base salary during three consecutive years out of the last ten years of credited service and (ii) the average of the participant’s three highest annual performance bonus periods, represented in each period by 50% of the actual bonus paid, in respect of the last five years of credited service, multiplied by (b) the number of credited years of service. An unreduced pension is payable if retirement is after age 55 with 30 or more years of service or after age 60. Early retirement reductions apply if a participant retires and does not meet these requirements. Retirement benefits paid from the Pension Plan are indexed at 50% of the annual increase in the consumer price index. All NEOs are currently senior management employees.

The table below illustrates the total annual pension entitlements at December 31, 2016 assuming the eligibility requirements for an unreduced pension have been satisfied. The present value of the accumulated benefits has been determined under the accrued benefit valuation method with the following assumptions:

 

Discount rate

   3.98% at year end 2016

Salary increases

   None

Inflation

   2.25% per year

Retirement age

   Age when first eligible for an unreduced pension (1)

Terminations

   None

Mortality Rates:

  

Pre-retirement

   None

Post-retirement

   Society of Actuaries RP2014 annuity/non-annuitant table without collar adjustment with full generational mortality improvement under Scale MP 2016

 

(1)  This is age 60 for all executives except for Mr. Neyland, who is eligible for an unreduced pension at age 57 and Mr. Reed, who is already eligible for an unreduced pension.

 

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PENSION BENEFITS

 

Name
(a)

   Plan Name
(b)
     Number of
Years Credited Service (1)
(#)
(c)
     Present Value
of Accumulated
Benefit
($)
(d)
 

C. Gregory Harper

    
US QPP
US SPP

 
    
2.92
2.92

 
    
57,000
396,000

 

Stephen J. Neyland

    
US QPP
US SPP

 
    
14.50
12.00

    
258,000
1,035,000

 

E. Chris Kaitson

    
US QPP
US SPP

 
    
15.58
15.58

 
    
1,136,000
967,000

 

Kerry C. Puckett

    
US QPP
US SPP

 
    
14.50
12.42

 
    
252,000
1,177,000

 

R. Poe Reed

    
US QPP
US SPP

 
    
1.26
1.26

 
    
26,000
148,000

 

 

(1)  For all NEOs US SPP service represents years of service as a senior management employee.

Employment Agreements

In 2014, Enbridge entered into an executive employment agreement with Mr. Harper and in 2001, Enbridge entered into an executive employment agreement with Mr. Kaitson. The term of the agreements continue until the earlier of voluntary retirement in accordance with Enbridge’s retirement policies for its senior employees, voluntary resignation, death or termination of employment by Enbridge. The agreements provide that Enbridge will pay severance benefits to Messrs. Harper and Kaitson as set forth in the table below, if employment is terminated. None of the remaining NEOs have an employment agreement with us or any other Enbridge affiliate. Since 2007, it has been Enbridge’s policy not enter into employment agreements granting “single trigger” voluntary termination rights in favor of the executive.

 

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The following table provides a summary of the incremental compensation that Enbridge would pay to Messrs. Harper and Kaitson under the terms of their employment agreements upon the occurrence of one of the foregoing events:

 

Type of Termination

  

Base Pay

  

Short-term Incentive

  

Long-term Incentive

  

Benefits

  

Pension

Resignation
(Voluntary)

   None    Payable in full if executive has worked the entire calendar year (1). Otherwise none.    Performance stock units are forfeited. Vested options must be exercised within 30 days of resignation or by the end of the original term, whichever is sooner. Unvested stock options are cancelled.    None    Credited service no longer earned.

Retirement
(Voluntary)

   None    Current year’s incentive is pro-rated based on retirement date.    Performance stock units prorated for retirement date and the value and performance is assessed at the end of the usual term. Performance stock options are prorated for the period of active employment in the 5 year period starting January 1 of the year of grant. They are exercisable until the later of three years after retirement or 30 days after the date by which share price targets must be met (or option expiry, if sooner). Stock options continue to vest and can be exercised for three years after retirement (or option expiry, if sooner).    Post retirement benefits begin.    Credited service no longer earned.

Constructive Dismissal
(Involuntary)

   Base salary is paid out in a lump sum representing two years.    The average of short-term incentive awards received in the past two years multiplied by two times (2) ; plus the current year’s short-term incentive, prorated based on service prior to termination.    Performance stock units are prorated to date of termination and the value and performance is assessed and paid at the end of the term. Vested stock options are exercisable in accordance with their terms. (3) Unvested stock options are paid in cash.    Benefits of two years’ value is paid out over a two year period. (4)    Two additional years of pension accrual are paid out in cash.

Not for

Cause (Involuntary)

Change of Control

         Performance stock units mature and value is assessed and paid based on performance measures achieved to date. All stock options vest.      

 

(1)  Mr. Kaitson has to be employed on the day of payout to receive his short-term incentive.
(2)  Mr. Kaitson’s short-term incentive payout uses gross amount of last bonus paid multiplied by two times.
(3)  Where applicable, both time and performance vesting conditions must have been met in order to be considered exercisable.
(4)  Not applicable to Mr. Harper.

 

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Performance stock options have the same termination provisions as incentive stock options except:

 

    For retirement, Enbridge prorates performance stock options for the period of active employment in the 5 year period starting January 1 of the year of grant. The executive officer can exercise these options until the later of three years after retirement or 30 days after the share price targets must be met (or up to the date the option expires, whichever is earlier), as long as the performance criteria are met;

 

    For death, unvested options are pro-rated and the plan assumes performance requirements have been met;

 

    For involuntary termination (not for cause), unvested options are pro-rated; and

 

    For change of control, the plan assumes the performance requirements have been met.

In addition, Mr. Harper will receive:

 

    Up to a maximum of $20,000 for financial or career counseling assistance.

 

    An amount in cash equal to the value of all of such executive officer’s accrued and unpaid vacation pay.

 

    Annual flexible perquisite, flex credit allowance and savings plan matching contributions over the severance period (2 years).

In addition, Mr. Kaitson will receive:

 

    Savings plan matching contributions over the severance period (2 years).

After his departure, Mr. Harper is subject to restrictions on (1) any practice or business in competition with Enbridge or its affiliates for one year, (2) disclosure of the confidential information of Enbridge or its affiliates indefinitely and (3) recruitment for two years. Mr. Kaitson is subject to restrictions on (1) disclosure of the confidential information of Enbridge or its affiliates indefinitely.

In the event of a termination that would result in severance benefits, Enbridge would owe incremental benefits to Mr. Harper with a value of approximately $4 million and Mr. Kaitson with a value of approximately $2 million. Such amounts assume that termination was effective as of December 31, 2016, and as a result include amounts earned through such time and are estimates of the amounts which would be paid out to Messrs. Harper and Kaitson upon termination under such circumstances. The actual amounts to be paid out can only be determined at the time of such executive’s separation from Enbridge.

Director Compensation

As a partnership, we are managed by our General Partner. The board of directors of our General Partner performs for us the functions of a board of directors of a business corporation. We are allocated 100% of the director compensation of these board members. Enbridge employees who are members of the board of directors of our General Partner do not receive any additional compensation for serving in those capacities.

Directors of our General Partner who are not officers or employees of our General Partner or its affiliates receive compensation as “non-employee directors,” which is an annual retainer value equal to $135,000 payable in cash. The chairman of the board of directors of our General Partner receives an additional annual cash retainer equal to $20,000. In addition, the chair of the Audit, Finance & Risk Committee receives an additional annual cash retainer equal to $15,000. The chair of any Special Committee that may be constituted from time to time receives $5,000 for each committee. Each member of a Special Committee receives $1,500 per meeting.

The Corporate Governance Guidelines provide an expectation that independent directors will hold a personal investment in us of at least two times the annual board retainer, which, based on the current annual

 

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retainer would equal $270,000. Directors would be expected to achieve the foregoing level of equity ownership by the later of October 10, 2018 or five years from the date he or she became a director. None of our independent directors has been a director for five years. Therefore, we consider that all of the directors are in compliance.

DIRECTOR COMPENSATION

 

Name
(a)

   Fees Earned or
Paid in Cash
($)
(b)
 

Dan A. Westbrook

  

Chairman of the Board

     159,500  

J. Herbert England

  

Audit, Finance & Risk Committee Chairman

     154,500  

John A. Crum

     150,000  

James G. Ivey

     150,000  

Edmund P. Segner III

     161,500  

C. Gregory Harper, Mark A. Maki and R. Poe Reed (1)

     —    

 

(1)  These directors are also employees of Enbridge or its subsidiaries and thus do not receive any compensation as a director in addition to their standard compensation as an employee of Enbridge or its subsidiaries.

Each director is indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law and will be reimbursed for all expenses incurred in attending to his or her duties as a director.

 

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COMPENSATION REPORT OF THE BOARD OF DIRECTORS

The Board of Directors of Midcoast Holdings, L.L.C has reviewed and discussed the Compensation Discussion and Analysis section of this report with management and, based on that review and discussion, has recommended that the Compensation Discussion and Analysis be included in this report.

 

/s/ C. Gregory Harper

  /s/ Mark A. Maki

C. Gregory Harper

  Mark A. Maki

President (Principal Executive Officer) and Director

  Senior Vice President and Director

/s/ R. Poe Reed

  /s/ John A. Crum

R. Poe Reed

  John A. Crum

Vice President & Chief Commercial Officer and Director

  Director

/s/ J. Herbert England

  /s/ Edmund P. Segner III

J. Herbert England

  Edmund P. Segner III

Director

  Director

/s/ James G. Ivey

  /s/ Dan A. Westbrook

James G. Ivey

  Dan A. Westbrook

Director

  Director

 

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

The following table sets forth information as of February 16, 2017 with respect to persons known to us to be the beneficial owners of more than 5% of any class of the Partnership’s units:

 

Name and Address of Beneficial Owner

  

Title of Class (1)

   Amount and
Nature of
Beneficial
Ownership
     Percent of
Class
 

Enbridge Energy Partners, L.P. (2)

   Class A common units      1,335,056        5.9  

1100 Louisiana St., Suite 3300

   Class B common units (3)      22,610,056        100.0  

Houston, TX 77002

   General Partner units      922,859        100.0  

OppenheimerFunds Inc. (4)

   Class A common units      4,481,651        19.8  

225 Liberty Street

        

New York, NY 10281

        

Oppenheimer SteelPath MLP Income Fund (5)

   Class A common units      3,100,729        13.7  

6803 S. Tucson Way

        

Centennial, CO 80112-3924

        

Kayne Anderson Capital Advisors, L.P. (6)

   Class A common units      2,562,572        11.3  

1800 Avenue of the Stars

        

Third Floor

        

Los Angeles, CA 90067

        

Clearbridge Investments, LLC (7)

   Class A common units      2,341,304        10.4  

620 8 th Avenue

        

New York, NY 10018

        

Atlantic Trust Group LLC (8)

   Class A common units      1,368,300        6.1  

3290 Northside Parkway

        

7 th Floor

        

Atlanta, GA 30327

        

Oppenheimer SteelPath MLP Select 40 Fund (9)

   Class A common units      1,339,510        5.9  

6803 S. Tucson Way

        

Centennial, CO 80112-3924

        

 

(1)  On January 26, 2017, we entered into the merger agreement with EECI whereby EECI will acquire all of our outstanding publicly held common units. The transaction is expected to close during the second quarter of 2017, subject to customary conditions. For further details, refer to Part II, Item 8. Financial Statements and Supplementary Data, Note 1. Organization and Nature of Operations.
(2)  As of February 16, 2017, EEP directly held 1,335,056 Class A common units and 22,610,056 Class B common units; 922,859 general partner units were held by Midcoast Holdings, a wholly owned subsidiary of EEP.
(3)  On February 15, 2017, the subordination period ended and all of our outstanding subordinated units converted into a Class B common units on a one-for-one basis.
(4)  OppenheimerFunds Inc. reported shared voting and dispositive power as to the 4,481,651 Class A common units in an amendment to its Schedule 13G, filed January 25, 2017.
(5)  Oppenheimer SteelPath MLP Income Fund reported sole voting power and shared dispositive power as to the 3,100,729 Class A common units in an amendment to Schedule 13G filed on January 25, 2017.
(6)  Kayne Anderson Capital Advisors, L.P. reported shared voting and dispositive power as to the 2,562,572 Class A common units in amendment no. 4 to its schedule 13G, filed January 10, 2017.
(7) 

Clearbridge Investments, LLC reported sole voting and dispositive power as to the 2,341,304 Class A common units in amendment no. 3 to its schedule 13G, filed February 14, 2017 and also noted that the interest of one account, ClearBridge American Energy MLP Fund, an investment company registered under

 

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  the Investment Company Act of 1940 and managed by ClearBridge investments, LLC, amounted to 1,571,580 units, or 6.95% of the total Class A common units outstanding.
(8)  Atlantic Trust Group LLC reported sole voting and dispositive power as to the 1,368,300 Class A common units in its schedule 13G, filed February 13, 2017.
(9)  Oppenheimer SteelPath MLP Select 40 Fund reported sole voting power and shared dispositive power as to the 1,339,510 Class A common units in an amendment to Schedule 13G filed on January 25, 2017.

SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS

The following table sets forth information as of February 16, 2017 with respect to each class of our units beneficially owned by the NEOs and directors and executive officers of Midcoast Holdings as a group:

 

    

Midcoast Energy Partner, L.P.

 

Name

  

Title of Class (1)

   Number of of
Class (2)
     Percent of Class  

Dan A. Westbrook (3)

   Class A common units      15,000      *  

John A. Crum

   Class A common units      12,000      *  

J. Herbert England

   Class A common units      5,000      *  

C. Gregory Harper

   Class A common units      6,620      *  

James G. Ivey

   Class A common units      10,000      *  

Mark A. Maki

   Class A common units      19,000      *  

R. Poe Reed (4)

   Class A common units      200      *  

Edmund P. Segner III

   Class A common units      12,000      *  

E. Chris Kaitson (5)

   Class A common units      2,250      *  

Stephen J. Neyland (6)

   Class A common units      8,270      *  

Kerry C. Puckett

   Class A common units      8,000      *  

All executive officers, directors and nominees as a group (15 persons)

   Class A common units      106,440      *  

 

* Less than 1%.
(1)  On January 26, 2017, we entered into the merger agreement with EECI whereby EECI will acquire all of our outstanding publicly held common units. The transaction is expected to close during the second quarter of 2017, subject to customary conditions. For further details, refer to Part II, Item 8. Financial Statements and Supplementary Data, Note 1. Organization and Nature of Operations.
(2)  Unless otherwise indicated, each beneficial owner has sole voting and investment power with respect to all of the Class A common units attributed to him or her.
(3)  Mr. Westbrook is the indirect owner of these units, which are held by the Westbrook Trust.
(4)  Mr. Reed is the indirect owner of these units, of which 100 units each are held by his son and his daughter.
(5)  The units beneficially owned by Mr. Kaitson are held by his wife.
(6)  The units beneficially owned by Mr. Neyland are held in a Family Trust for which Mr. Neyland is a co-trustee as well as a beneficiary.

 

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SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

The following table provides information as of December 31, 2016 with respect to Class A common units that may be issued under the 2016 Midcoast Energy Partners, L.P. Long-Term Incentive Plan, or our LTIP: Upon consummation of the Merger, all Class A common units registered with respect to the LTIP will be deregistered and no further grants under the LTIP will be made.

 

Plan category

   Number of
securities to
be issued
upon exercise
of
outstanding
options,
warrants and
rights (1)
     Weighted
average
exercise price
of
outstanding
options,
warrants and
rights
     Number of
securities
remaining
available for
future issuance
under equity
compensation
plans (2)
 

Equity compensation plans approved by security holders

     N/A        N/A        3,750,000  

Equity compensation plans not approved by security holders

     —          —          —    
        

 

 

 

Total

           3,750,000  
        

 

 

 

 

(1)  We have not previously granted equity incentive awards in us to any person pursuant to the LTIP.
(2)  Reflects the Class  A common units available for issuance pursuant to the LTIP.

Item 13. Certain Relationships and Related Transactions, and Director Independence

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

As of December 31, 2016, Enbridge Energy Partners owned 1,335,056 Class A common units and 22,610,056 subordinated units representing a 52% limited partner interest in us. In addition, our General Partner owns 922,859 general partner units representing a 2% general partner interest in us. On February 15, 2017, the subordinated units converted into Class B common units on a one-for-one basis.

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. For further discussion of these and other related party transactions, refer to Part II, Item 8. Financial Statements and Supplementary Data, under Note 23. Related Party Transactions.

REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS

If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our General Partner as appropriate. The board of directors then determines whether it is advisable to constitute a special committee of independent directors to evaluate the proposed transaction. If a special committee is appointed, the committee obtains information regarding the proposed transaction from management and determines whether it is advisable to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the special committee retains such counsel or financial advisor, it considers the advice and, in the case of a financial advisor, such advisor’s opinion as to whether the transaction is fair to us and all of our unitholders.

Potential transactions with related persons that are not financially significant so as to require review by the board of directors are disclosed to the President of our General Partner and reviewed for compliance with the Enbridge Statement on Business Conduct. The President may also consult with legal counsel in making such determination. If a related person transaction occurred and was later found not to comply with the Statement on Business Conduct, the transaction would be reported to the board of directors for further review and ratification or remedial action.

 

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The Enbridge Statement of Business Conduct sets forth policies and procedures for the review and approval of certain transactions with persons affiliated with us.

DIRECTOR INDEPENDENCE

For a discussion of director independence, see Item 10. Directors, Executive Officers and Corporate Governance.

Item 14. Principal Accountant Fees and Services

The following table sets forth the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP, our principal independent auditors, for each of our last two fiscal years.

 

     For the year ended
December 31,
 
     2016      2015  
     (in millions)  

Audit fees (1)

   $ 1.9      $ 2.4  

Tax fees (2)

     0.2        0.2  
  

 

 

    

 

 

 

Total

   $ 2.1      $ 2.6  
  

 

 

    

 

 

 

 

(1)  Audit fees consist of fees billed for professional services rendered for the audit of our consolidated financial statements, reviews of our interim consolidated financial statements, audits of various subsidiaries for statutory and regulatory filing requirements and our debt and equity offerings.
(2)  Tax fees consist of fees billed for professional services rendered for federal and state tax compliance for Partnership tax filings and unitholder K-1’s.

Engagements for services provided by PricewaterhouseCoopers LLP are subject to pre-approval by the Audit, Finance, and Risk Committee of Midcoast Holdings board of directors; however, services up to $50,000 may be approved by the Chairman of the Audit, Finance, and Risk Committee, under the board of directors’ delegated authority. All services in 2016 were approved by the Audit, Finance, and Risk Committee.

 

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PART IV

Item 15. Exhibits and Financial Statement Schedules

The following documents are filed as a part of this report:

 

  (1) Financial Statements.

The following financial statements and supplementary data are included in Part II, Item 8. Financial Statements and Supplementary Data of this Form 10-K.

 

  a. Report of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
  b. Consolidated Statements of Income for the years ended December 31, 2016, 2015 and 2014.
  c. Consolidated Statements of Comprehensive Income for the years ended December 31, 2016, 2015 and 2014.
  d. Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014.
  e. Consolidated Statements of Financial Position as of December 31, 2016 and 2015.
  f. Consolidated Statements of Partners’ Capital for the years ended December 31, 2016, 2015 and 2014.
  g. Notes to the Consolidated Financial Statements.

 

  (2) Financial Statement Schedules.

All schedules have been omitted because they are not applicable, the required information is shown in the consolidated financial statements or Notes thereto or the required information is immaterial.

 

  (3) Exhibits.

Reference is made to the “Index of Exhibits” following the signature page, which is hereby incorporated into this Item.

 

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Midcoast Energy Partners, L.P.

(Registrant)

By:  
 

Midcoast Holdings, L.L.C.,

as General Partner

 

Date: February 16, 2017     By:  

/s/ C. Gregory Harper

      C. Gregory Harper
      President
      (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 16, 2017 by the following persons on behalf of the Registrant and in the capacities indicated.

 

/s/ C. Gregory Harper

  

/s/ Mark A. Maki

C. Gregory Harper

President

(Principal Executive Officer) and Director

  

Mark A. Maki

Senior Vice President and

Director

/s/ Stephen J. Neyland

Stephen J. Neyland

Vice President — Finance

(Principal Financial Officer)

  

/s/ Noor S. Kaissi

Noor S. Kaissi

Controller

(Principal Accounting Officer)

/s/ J. Herbert England

J. Herbert England

Director

  

/s/ Dan A. Westbrook

Dan A. Westbrook

Director

/s/ John A. Crum

John A. Crum

Director

  

/s/ James G. Ivey

James G. Ivey

Director

/s/ Edmund P. Segner III

Edmund P. Segner III

Director

  

/s/ R. Poe Reed

R. Poe Reed

Vice President & Chief Commercial Officer and

Director

 

 

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Index of Exhibits

Each exhibit identified below is filed as a part of this annual report. Exhibits included in this filing are designated by an asterisk (“*”); all exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with a “+” constitute a management contract or compensatory plan arrangement required to be filed as an exhibit to this report pursuant to Item 15(b) of Form 10-K.

 

Exhibit
Number

  

Description

  2.1    Agreement and Plan of Merger by and among Enbridge Energy Company, Inc., Enbridge Holdings (Leather) L.L.C., Midcoast Energy Partners, L.P. and Midcoast Holdings, L.L.C. dated as of January 26, 2017 (incorporated by reference to Exhibit 2.1 of our of our Current Report on Form 8-K, filed on January 27, 2017).
  3.1    Certificate of Limited Partnership of Midcoast Energy Partners, L.P., dated May 30, 2013 (incorporated by reference to Exhibit 3.1 of our Registration Statement on Form S-1 (Registration No. 333-189341), initially filed on June 14, 2013, as amended).
  3.2    First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P. dated November 13, 2013 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed on November 18, 2013).
  4.1    Specimen Unit Certificate for the Class A Common Units (included as Exhibit A to the Form of First Amended and Restated Agreement of Limited Partnership of the Registrant) (incorporated herein by reference to Appendix A of the First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P. under Exhibit 3.1 of our Current Report on Form 8-K, filed on November 18, 2013).
10.1    Support Agreement by and among Midcoast Energy Partners, L.P., Enbridge Energy Company, Inc. and Enbridge Energy Partners, L.P. dated as of January 26, 2017 (incorporated by reference to Exhibit 10.1 of our of our Current Report on Form 8-K, filed on January 27, 2017).
10.2    Contribution, Conveyance and Assumption Agreement by and among Midcoast Energy Partners, L.P., Enbridge Energy Partners, L.P., Midcoast Holdings, L.L.C., Midcoast Operating L.P. and Midcoast OLP GP, L.L.C. dated as of November 13, 2013, (incorporated by reference to Exhibit 10.1 of our of our Current Report on Form 8-K, filed on November 18, 2013).
10.3    Omnibus Agreement, dated as of November 13, 2013, by and among Midcoast Energy Partners, L.P., Midcoast Holdings, L.L.C., Enbridge Energy Partners, L.P. and Enbridge Inc. (incorporated by reference to Exhibit 10.2 of our of our Current Report on Form 8-K, filed on November 18, 2013).
10.4    Credit Agreement, dated as of November 13, 2013, by and among Midcoast Energy Partners, L.P., as Co-Borrower, Midcoast Operating L.P., as Co-Borrower, the subsidiary guarantors party thereto, Bank of America, N.A., as Administrative Agent, Letter of Credit Issuer, Swing Line Lender and lender, and each of the other lenders party thereto (incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K, filed on November 18, 2013).
10.5    Amendment No. 1 to Credit Agreement and Extension Agreement, dated as of September 30, 2014, by and among Midcoast Energy Partners, L.P., Midcoast Operating, L.P., the subsidiary guarantors party thereto, the lenders party thereto and Bank of America, N.A., as administrative agent for the lenders (incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K, filed on October 6, 2014).
10.6    Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P., dated as of July 29, 2015 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed on July 29, 2015).

 

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Exhibit
Number

  

Description

10.7    Amendment No. 2 to Credit Agreement and Extension Agreement, dated as of September 3, 2015, by and among Midcoast Energy Partners, L.P., Midcoast Operating, L.P., the subsidiary guarantors party thereto, the lenders party thereto and Bank of America, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed on September 9, 2015).
10.8    Amendment No. 3 to Credit Agreement, dated September 30, 2016 by and among Midcoast Energy Partners, L.P., Midcoast Operating, L.P., the subsidiary guarantors party thereto, the lenders party thereto and Bank of America, N.A., as administrative agent. (incorporated by reference to Exhibit 10.1 on Form 10-Q, filed on October 31, 2016).
10.9    Note Purchase Agreement by and among Midcoast Energy Partners, L.P. and the purchasers named therein, dated as of September 30, 2014 (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed on October 6, 2014).
10.10    Guaranty Agreement dated as of September 30, 2014, made by each guarantor in favor of the purchasers and other holders from time to time of the Notes in the Note Purchase Agreement (incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K, filed on October 6, 2014).
10.11    Intercorporate Services Agreement, dated as of November 13, 2013, by and between EEP and Midcoast Energy Partners, L.P. (incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K, filed on November 18, 2013).
10.12    Financial Support Agreement, dated as of November 13, 2013, by and between Midcoast Operating, L.P. and EEP (incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K, filed on November 18, 2013).
10.13    Amended and Restated Allocation Agreement, dated as of November 13, 2013, by and among Midcoast Energy Partners, L.P., Enbridge Inc., EEP and Enbridge Income Fund Holdings Inc., (incorporated by reference to Exhibit 10.6 of our Current Report on Form 8-K, filed on November 18, 2013).
10.14    Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P., dated as of November 13, 2013 (incorporated by reference to Exhibit 10.8 of our Current Report on Form 8-K, filed on November 18, 2013).
10.15    Subordination Agreement dated November 13, 2013 by and among Midcoast Energy Partners, L.P., Midcoast Operating, L.P., other credit parties from time to time party there to, Enbridge Energy Partners, L.P., and Bank of America, N.A. (incorporated by reference to Exhibit 10.9 of our Quarterly Report on Form 10-Q, filed on December 20, 2013).
10.16    Subordination Agreement dated as of September 30, 2014, by and among Midcoast Energy Partners, L.P., other obligors from time to time party thereto, Enbridge Energy Partners, L.P., and certain of its subsidiaries and affiliates from time to time party thereto in favor of the holders from time to time of the Notes in the Note Purchase Agreement (incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K, filed on October 6, 2014).
10.17    Amended and Restated Subordination Agreement, dated as of September 30, 2014, by and among Midcoast Energy Partners, L.P., Midcoast Operating, L.P., the other credit parties from time to time party thereto and Enbridge Energy Partners, L.P. in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.5 of our Current Report on Form 8-K, filed on October 6, 2014).

 

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Exhibit
Number

 

Description

  +10.18   Executive Employment Agreement, entered into February 11, 2014, between C. Gregory Harper, the Executive, and Enbridge Employee Services, Inc., effective January 30, 2014 (incorporated by reference to our Annual Report on Form 10-K for the year ended December 31, 2013, filed on February 18, 2014).
    10.19   Form of Long-Term Incentive Plan of Midcoast Energy Partners, L.P. (incorporated by reference to Exhibit 10.3 to our Registration Statement on Form S-1 (Registration No. 33-189341), initially filed on June 14, 2013, as amended.)
    10.20   Purchase and Sale Agreement by and between Enbridge Energy Partners, L.P. and Midcoast Energy Partners, L.P. dated as of June 18, 2014 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed on June 19, 2014).
    10.21   Form of Performance Stock Unit Agreement of Midcoast Holdings, L.L.C. (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, filed on May 1, 2015).
    10.22   Form of Indemnification Agreement of Midcoast Holdings, L.L.C., together with a schedule of individuals who entered into an agreement in substantially the same form and the date of the agreement. (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, filed on October 30, 2015).
  *21.1   Subsidiaries of the Registrant.
  *23.1   Consent of PricewaterhouseCoopers LLP.
  *23.2   Consent of Deloitte & Touche LLP.
  *31.1   Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  *31.2   Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  *32.1   Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  *32.2   Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
  *99.1   Audited financial statements as of December 31, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014 of Texas Express Pipeline LLC.
*101.INS   XBRL Instance Document.
*101.SCH   XBRL Taxonomy Extension Schema Document.
*101.CAL   XBRL Taxonomy Extension Calculation Linkbase Document.
*101.DEF   XBRL Taxonomy Extension Definition Linkbase Document.
*101.LAB   XBRL Taxonomy Extension Label Linkbase Document.
*101.PRE   XBRL Taxonomy Extension Presentation Linkbase Document.

Copies of Exhibits may be obtained upon written request of any Unitholder to Investor Relations, Midcoast Energy Partners, L.P., 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

 

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Exhibit 21.1

MIDCOAST ENERGY PARNTERS, L.P.

Subsidiaries of the Registrant

 

Company Name

   State of Incorporation/
Formation/Organization

ELTM, L.P.

   Delaware

Enbridge Energy Marketing, L.L.C.

   Delaware

Enbridge G & P (East Texas) L.P.

   Texas

Enbridge G & P (North Texas) L.P.

   Texas

Enbridge G & P (Oklahoma) L.P.

   Texas

Enbridge Gathering (North Texas) L.P.

   Texas

Enbridge Holdings (Mississippi) L.L.C.

   Delaware

Enbridge Holdings (Texas Systems) L.L.C.

   Delaware

Enbridge Liquids Marketing (North Texas) L.P.

   Delaware

Enbridge Marketing (North Texas) L.P.

   Delaware

Enbridge Marketing (U.S.) L.L.C.

   Delaware

Enbridge Marketing (U.S.) L.P.

   Texas

Enbridge Partners Risk Management, L.P.

   Delaware

Enbridge Pipelines (East Texas) L.P.

   Texas

Enbridge Pipelines (North Texas) L.P.

   Texas

Enbridge Pipelines (Oklahoma Transmission) L.L.C.

   Delaware

Enbridge Pipelines (Texas Gathering) L.P.

   Delaware

Enbridge Pipelines (Texas Intrastate) L.P.

   Texas

Enbridge Pipelines (Texas Liquids) L.P.

   Texas

H&W Pipeline, L.L.C.

   Alabama

Midcoast OLP GP, L.L.C.

   Delaware

Midcoast Operating, L.P.

   Texas

 

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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-198179) of Midcoast Energy Partners, L.P. of our report dated February 16, 2017 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 16, 2017

 

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Exhibit 23.2

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in the Registration Statement No. 333-198179 on Form S-8 of Midcoast Energy Partners, L.P. of our report dated February 13, 2017, relating to the financial statements of Texas Express Pipeline LLC as of December 31, 2016 and 2015, and for the years ended December 31, 2016, 2015 and 2014, appearing in this Annual Report on Form 10-K of Midcoast Energy Partners, L.P. for the year ended December 31, 2016.

/s/ Deloitte & Touche LLP

Houston, Texas

February 16, 2017

 

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Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, C. Gregory Harper, certify that:

 

  1. I have reviewed this Annual Report on Form 10-K of Midcoast Energy Partners, L.P.;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

  4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

  a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

 

  5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

  a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

  b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 16, 2017

 

By:  
  /s/ C. Gregory Harper
  C. Gregory Harper
  President
  (Principal Executive Officer)
  Midcoast Holdings, L.L.C. (as the General Partner)

 

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Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Stephen J. Neyland, certify that:

 

  1. I have reviewed this Annual Report on Form 10-K of Midcoast Energy Partners, L.P.;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

  4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

 

  a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

  c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

 

  5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

  a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

  b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 16, 2017

 

By:  
  /s/ Stephen J. Neyland
  Stephen J. Neyland
  Vice President — Finance
  (Principal Financial Officer)
  Midcoast Holdings, L.L.C. (as the General Partner)

 

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Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

Pursuant to Section 906(a) of the Sarbanes-Oxley Act of 2002

Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18 of the United States Code

The undersigned, being the Principal Executive Officer of Midcoast Holdings, L.L.C., as general partner of Midcoast Energy Partners, L.P., hereby certifies that our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “Annual Report”) filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)), as amended, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of Midcoast Energy Partners, L.P.

Date: February 16, 2017

 

By:  
  /s/ C. Gregory Harper
  C. Gregory Harper
  President
  (Principal Executive Officer)
  Midcoast Holdings, L.L.C. (as the General Partner)

 

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Exhibit 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

Pursuant to Section 906(a) of the Sarbanes-Oxley Act of 2002

Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18 of the United States Code

The undersigned, being the Principal Financial Officer of Midcoast Holdings, L.L.C., as general partner of Midcoast Energy Partners, L.P., hereby certifies that our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “Annual Report”) filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)), as amended, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained in the Annual Report fairly presents, in all material respects, the financial condition and results of operations of Midcoast Energy Partners, L.P.

Date: February 16, 2017

 

By:  
  /s/ Stephen J. Neyland
  Stephen J. Neyland
  Vice President — Finance
  (Principal Financial Officer)
  Midcoast Holdings, L.L.C. (as the General Partner)

 

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Exhibit 99.1

Texas Express Pipeline LLC

Financial Statements

for the Years Ended December 31, 2016, 2015 and 2014

 

D-197


Table of Contents

Texas Express Pipeline LLC

Index to Financial Statements

 

     Page  

Independent Auditors’ Report

     D-199  

Financial Statements:

  

Balance Sheets

     D-200  

Statements of Operations

     D-201  

Statements of Cash Flows

     D-202  

Statements of Members’ Equity

     D-203  

Notes to Financial Statements

     D-204  

 

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Table of Contents

INDEPENDENT AUDITORS’ REPORT

To the Management Committee of Texas Express Pipeline LLC

Houston, Texas

We have audited the accompanying financial statements of Texas Express Pipeline LLC (the “Company”), which comprise the balance sheets as of December 31, 2016 and 2015 and the related statements of operations, cash flows and members’ equity for the years ended December 31, 2016, 2015 and 2014, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Texas Express Pipeline LLC as of December 31, 2016 and 2015 and the results of its operations and its cash flows for the years ended December 31, 2016, 2015 and 2014 in accordance with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 13, 2017

 

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Table of Contents

Texas Express Pipeline LLC

Balance Sheets

December 31, 2016 and 2015

(in thousands of dollars)

 

     December 31,  
     2016      2015  

Assets

     

Current assets

     

Cash and cash equivalents

   $ 7,898      $ 9,898  

Accounts receivable — related parties

     11,035        11,590  

Other current assets

     544        687  
  

 

 

    

 

 

 

Total current assets

     19,477        22,175  

Property, plant and equipment, net

     905,933        934,608  
  

 

 

    

 

 

 

Total assets

   $ 925,410      $ 956,783  
  

 

 

    

 

 

 

Liabilities and Members’ Equity

     

Current liabilities

     

Accounts payable — trade

   $ 91      $ 410  

Accounts payable — related parties

     136        181  

Accrued ad valorem taxes

     5,381        4,773  

Deferred revenue attributable to make-up rights

     7,084        9,950  

Deferred revenue attributable to in-transit volumes

     4,201        4,635  

Other current liabilities

     854        993  
  

 

 

    

 

 

 

Total current liabilities

     17,747        20,942  

Other liabilities

     1,689        1,327  

Commitments and contingencies (see Note 6)

     

Members’ equity

     905,974        934,514  
  

 

 

    

 

 

 

Total liabilities and members’ equity

   $ 925,410      $ 956,783  
  

 

 

    

 

 

 

The accompanying notes are an integral part of these financial statements.

 

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Texas Express Pipeline LLC

Statements of Operations

For the Years Ended December 31, 2016, 2015 and 2014

(in thousands of dollars)

 

     For the Year Ended
December 31,
 
     2016      2015      2014  

Revenues

   $ 127,091      $ 122,383      $ 70,524  

Costs and expenses

        

Depreciation and accretion

     26,730        26,662        25,118  

Operating costs and expenses

     16,945        13,196        10,506  

General and administrative

     317        312        187  
  

 

 

    

 

 

    

 

 

 

Total costs and expenses

     43,992        40,170        35,811  
  

 

 

    

 

 

    

 

 

 

Operating income

     83,099        82,213        34,713  

Provision for income taxes

     149        307        385  
  

 

 

    

 

 

    

 

 

 

Net income

   $ 82,950      $ 81,906      $ 34,328  
  

 

 

    

 

 

    

 

 

 

The accompanying notes are an integral part of these financial statements.

 

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Texas Express Pipeline LLC

Statements of Cash Flows

For the Years Ended December 31, 2016, 2015 and 2014

(in thousands of dollars)

 

     For the Year Ended
December 31,
 
     2016     2015     2014  

Operating activities

      

Net income

   $ 82,950     $ 81,906     $ 34,328  

Reconciliation of net income to net cash flows provided by operating activities:

      

Depreciation and accretion expense

     26,730       26,662       25,118  

Loss on sale of assets

     51       —         —    

Deferred income tax expense

     81       122       385  

Effect of changes in operating accounts:

      

Decrease (increase) in accounts receivable

     555       (2,784     (2,483

Decrease (increase) in other current assets

     143       319       (300

Decrease in accounts payable

     (187     (112     (4,459

Increase in accrued ad valorem taxes

     608       396       3,574  

Increase (decrease) in deferred revenue attributable to make-up rights

     (2,866     (2,584     8,676  

Increase (decrease) in deferred revenue attributable to in-transit volumes

     (434     169       2,450  

Increase (decrease) in other current liabilities

     (138     332       (688
  

 

 

   

 

 

   

 

 

 

Net cash flows provided by operating activities

     107,493       104,426       66,601  
  

 

 

   

 

 

   

 

 

 

Investing activities

      

Capital expenditures

     (664     (11,930     (49,411

Return of construction-related security deposit

     2,622       —         —    

Proceeds from sale of assets

     39       4,692       19  
  

 

 

   

 

 

   

 

 

 

Cash provided by (used in) investing activities

     1,997       (7,238     (49,392
  

 

 

   

 

 

   

 

 

 

Financing activities

      

Contributions from Members

     —         9,346       47,790  

Distributions to Members

     (111,490     (109,790     (58,350
  

 

 

   

 

 

   

 

 

 

Cash used in financing activities

     (111,490     (100,444     (10,560
  

 

 

   

 

 

   

 

 

 

Net change in cash and cash equivalents

     (2,000     (3,256     6,649  

Cash and cash equivalents, January 1

     9,898       13,154       6,505  
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, December 31

   $ 7,898     $ 9,898     $ 13,154  
  

 

 

   

 

 

   

 

 

 

Supplemental cash flow information

      

Current liabilities for capital expenditures at December 31

   $ 3     $ 318     $ 5,845  
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

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Texas Express Pipeline LLC

Statements of Members’ Equity

For the Years Ended December 31, 2016, 2015 and 2014

(in thousands of dollars)

 

     Enterprise
Products
Operating
LLC
(35%)
    Midcoast
Operating,
L.P.
(35%)
    WGR
Operating,

LP
(20%)
    DCP
Partners
Logistics,
LLC
(10%)
    Total  

Balance — January 1, 2014

   $ 323,977     $ 323,976     $ 188,766     $ 92,565     $ 929,284  

Net income

     12,015       12,014       6,866       3,433       34,328  

Contributions from Members

     18,006       18,006       6,623       5,155       47,790  

Distributions to Members

     (20,423     (20,422     (11,670     (5,835     (58,350
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance — December 31, 2014

     333,575       333,574       190,585       95,318       953,052  

Net income

     28,667       28,667       16,382       8,190       81,906  

Contributions from Members

     3,270       3,270       1,880       926       9,346  

Distributions to Members

     (38,426     (38,426     (21,959     (10,979     (109,790
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance — December 31, 2015

     327,086       327,085       186,888       93,455       934,514  

Net income

     29,032       29,033       16,590       8,295       82,950  

Distributions to Members

     (39,026     (39,026     (22,292     (11,146     (111,490
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance — December 31, 2016

   $ 317,092     $ 317,092     $ 181,186     $ 90,604     $ 905,974  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

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Texas Express Pipeline LLC

Notes to Financial Statements

1. Company Organization and Description of Business

Company Organization

Texas Express Pipeline LLC is a Delaware limited liability company formed in September 2011 to design, construct, operate and own the Texas Express Pipeline. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Company” within these notes are intended to mean Texas Express Pipeline LLC.

At December 31, 2016, our membership interests were owned as follows: (i) 35% by Enterprise Products Operating LLC (“Enterprise”); (ii) 35% by Midcoast Operating, L.P., formerly known as Enbridge Midcoast Energy, LP (“Enbridge”); (iii) 20% by WGR Operating, LP (“Anadarko”); and (iv) 10% by DCP Partners Logistics, LLC (“DCP”). Enterprise, Enbridge, Anadarko and DCP are referred to individually as a “Member” and collectively as the “Members.”

Description of Business

The Texas Express Pipeline, which commenced operations in November 2013, is a 20-inch diameter natural gas liquids (“NGL”) pipeline that originates in Skellytown, Texas and extends 594 miles to NGL fractionation and storage facilities located in Mont Belvieu, Texas. Throughput capacity for the Texas Express Pipeline is approximately 280 thousand barrels per day (“MBPD”) (unaudited). The Texas Express Pipeline, with its pipeline connections to the Mid-America Pipeline System and the Front Range Pipeline (both of which are owned by affiliates), provides producers in West and Central Texas, the Rocky Mountains, Southern Oklahoma and the Mid-Continent regions with takeaway capacity for NGLs and enhanced access to Gulf Coast markets.

Enterprise serves as operator of the Texas Express Pipeline.

2. Significant Accounting Policies

Our financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles (“GAAP”).

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

In preparing these financial statements, we have evaluated subsequent events for potential recognition or disclosure through February 13, 2017, the issuance date of the financial statements.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and may also include highly liquid investments with original maturities of less than three months from the date of purchase.

Contingencies

Certain conditions may exist as of the date the financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management and legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise of judgment. In assessing loss contingencies related to pending legal proceedings or unasserted claims that may result in such proceedings, our legal counsel evaluates the perceived merits of such matters, including the amount of relief sought or expected to be sought therein.

 

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If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of the liability can be estimated, then the estimated liability would be recognized and the nature of the contingent liability would be disclosed in our financial statements.

If the assessment indicates that a loss contingency is not probable, but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable), would be disclosed, if material.

Loss contingencies considered remote are generally not disclosed or recognized unless they involve guarantees that are material to us, in which case the nature of the guarantee would be disclosed.

We had no loss contingency matters requiring recognition or disclosure at December 31, 2016 or 2015.

Environmental Costs

Our operations are subject to extensive federal and state environmental regulations. Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination will be capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. There were no environmental remediation liabilities incurred as of December 31, 2016 or 2015.

Estimates

Preparing our financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation methods used for fixed assets; (ii) measurement of fair value and projections used in impairment testing of fixed assets; and (iii) revenue and expense accruals.

Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our financial statements.

Fair Value Information

The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values based on their short-term nature.

Impairment Testing for Long-Lived Assets

Long-lived assets such as pipelines and facilities are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market

 

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participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. No asset impairment charges were recognized during the years ended December 31, 2016, 2015 and 2014.

Income Taxes

Income taxes reflect our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

We are organized as a pass-through entity for federal income tax purposes. As a result, our financial statements do not provide for such taxes, and our Members are individually responsible for their allocable share of our taxable income for federal income tax purposes.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period.

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the reporting periods it benefits. Our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets.

Asset retirement obligations (“AROs”) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with the retirement of property, plant and equipment assets. We recognize the fair value of a liability for an ARO in the period in which it is incurred and can be reasonably estimated, with the associated asset retirement cost capitalized as part of the carrying value of the asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-term asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts.

See Note 3 for additional information regarding our property, plant and equipment and related AROs.

Revenue Recognition

Our results of operations are dependent upon the volume of mixed NGLs we transport and deliver and the associated tariffs we charge for such services. The tariffs we charge for interstate and intrastate transportation services are regulated by the Federal Energy Regulatory Commission and Texas Railroad Commission, respectively.

We recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists between us and the shipper (e.g., published tariffs), (ii) delivery of the shipper’s volumes has occurred, (iii) the tariff is fixed or determinable and (iv) collectibility of the amount owed by the shipper is reasonably assured.

 

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In accordance with our tariffs, we invoice shippers for transportation services upon receipt of their volumes; however, for revenue recognition purposes, the transportation revenue we record is based on delivered volumes. Revenues attributable to “in transit” volumes at each balance sheet date are deferred until such volumes are delivered back to the shipper. At December 31, 2016, deferred revenues attributable to in transit volumes totaled $4.2 million. This amount was recognized as revenue in January 2017.

Under certain of our transportation agreements, counterparties are required to ship a minimum volume each month. These arrangements typically entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over an agreed-upon period (referred to as shipper “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the shipper’s ability to meet the minimum volume commitment has expired (typically a one year contractual period), or when the pipeline is otherwise released from its transportation service performance obligation. At December 31, 2016, our deferred revenues attributable to make-up rights totaled $7.1 million. We expect to recognize these amounts as revenue in 2017.

See Note 5 for information regarding related party transportation service agreements.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 606, Revenue From Contracts With Customers (“ASC 606”). The core principle in the new guidance is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. In order to apply this core principle, companies will apply the following five steps in determining the amount of revenues to recognize: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management’s judgment and an analysis of the contract’s material terms and conditions.

We are reviewing our revenue contracts in light of this new accounting guidance and currently do not anticipate that there will be a material impact on our financial statements. We will adopt the new standard on January 1, 2018 using the modified retrospective method, which will require us to apply the new guidance to (i) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity for any differences between previously recognized revenues and the amount of revenue that would have been recognized under ASC 606 and (ii) all new revenue contracts entered into after January 1, 2018. Revenues presented for any comparative historical periods prior to 2018 would not be revised.

3. Property, Plant and Equipment

The historical cost of our property, plant and equipment and related accumulated depreciation balances were as follows at the dates indicated:

 

     Estimated
Useful Life

in Years
     December 31,  
        2016      2015  

Pipeline assets

     32-38      $ 985,078      $ 987,013  

Transportation equipment

     6        725        857  

Land

        2,351        2,351  

Construction in progress

        200        302  
     

 

 

    

 

 

 

Total

        988,354        990,523  

Less accumulated depreciation

        82,421        55,915  
     

 

 

    

 

 

 

Property, plant and equipment, net

      $ 905,933      $ 934,608  
     

 

 

    

 

 

 

 

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Depreciation expense was $26.6 million, $26.7 million and $25.1 million for the years ended December 31, 2016, 2015 and 2014, respectively. In November 2014, the estimated useful lives of our pipeline assets were revised in connection with a formal depreciation study. The study indicated that the estimated useful lives of these assets ranged from 32 years to 38 years, which was lower than our previous useful life estimate of 40 years for this asset group. We accounted for this change in estimate prospectively. The effect of this change in accounting estimate was an increase in depreciation expense (and corresponding reduction in net income) of $0.5 million, for the year ended December 31, 2014.

In January 2016, we received $2.6 million of deposits from a utility company that were made in connection with the construction of our pipeline system. The return of this cash reduced the carrying value of our pipeline assets.

Asset Retirement Obligations

Our AROs result from pipeline right-of-way agreements associated with our operations. The following table presents information regarding our asset retirement liabilities for the periods indicated:

 

     For the Year Ended
December 31,
 
     2016      2015      2014  

Balance of ARO at beginning of year

   $ 820      $ 760      $ 704  

Revisions in estimated cash flows

     (138      —          —    

Accretion expense

     65        60        56  
  

 

 

    

 

 

    

 

 

 

Balance of ARO at end of year

   $ 747      $ 820      $ 760  
  

 

 

    

 

 

    

 

 

 

Property, plant and equipment at December 31, 2016, 2015 and 2014 include $0.5 million, $0.7 million and $0.7 million, respectively, of asset retirement costs that were capitalized as an increase in the associated long-lived asset.

The following table presents our forecast of accretion expense for the years indicated:

 

2017

 

2018

 

2019

 

2020

 

2021

$59

  $63   $68   $74   $80

4. Members’ Equity

As a limited liability company, our Members are not personally liable for any of our debts, obligations or other liabilities. Income or loss amounts are allocated to our Members based on their respective member interests. Cash contributions by and distributions to Members are also based on their respective membership interests.

Cash contributions from Members were used to fund capital projects. Our Members may be required in the future to make additional cash contributions in amounts determined by our Management Committee, which is responsible for conducting our affairs in accordance with the LLC Agreement. Cash distributions to Members are also determined by our Management Committee.

5. Related Party Transactions

Since we have no employees, our project management, operating functions and general and administrative support services are provided by employees of an affiliate of Enterprise. For the years ended December 31, 2016, 2015 and 2014, our reimbursements to Enterprise for payroll costs were $1.9 million, $1.5 million and $1.3 million, respectively. Also for the years ended December 31, 2016, 2015 and 2014, we paid Enterprise $2.2 million, $2.1 million and $2.0 million in management fees, respectively.

 

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Affiliates of Anadarko, Enbridge, DCP and Enterprise executed transportation service agreements (“TSAs”) with us in 2013 that involve monthly minimum volume commitments and make-up rights. Under these arrangements, each shipper is invoiced for its monthly volume commitment and, if needed, the shipper has the following twelve month period in which to make up any volume shortfall that they have paid for. Each of these TSAs has an initial term of 15 years. For years 1 through 10, the shipper is invoiced monthly for its volume commitment, which ceases in October 2023. For years 11 through 15, there is no monthly volume commitment, but the shipper has dedicated production from certain facilities to our pipeline. The TSAs may be renewed after the initial 15 year contract term expires. Transportation rates under the affiliate TSAs range from 4.52 cents per gallon for contract volumes to 4.37 cents per gallon for make-up volumes.

The following table presents aggregate average daily volume commitments remaining under the TSAs for the years indicated (in thousands of barrels per day):

 

Year

   Total  

2017

     159  

2018

     193  

2019

     196  

2020

     204  

2021

     208  

2022

     223  

2023

     234  

We have a joint tariff arrangement with Front Range Pipeline LLC (“Front Range”) for transportation volumes that originate on the Front Range Pipeline. Front Range is owned by Anadarko, DCP and Enterprise. At December 31, 2016 and 2015, our related party receivables from Front Range were $6.6 million and $5.9 million, respectively.

We also have a joint tariff arrangement with Mid-America Pipeline Company, LLC (“Mid-America”) for transportation volumes that originate on the Mid-America Pipeline System. At December 31, 2016 and 2015, our related party receivables from Mid-America were $3.1 million and $4.1 million, respectively.

6. Commitments and Contingencies and Significant Risks

Regulatory and Legal

As part of our normal business activities, we are subject to various laws and regulations, including those related to environmental matters. In the opinion of management, compliance with existing laws and regulations is not expected to have a material effect on our financial position, results of operations or cash flows.

Also, in the normal course of business, we may be a party to lawsuits and similar proceedings before various courts and governmental agencies involving, for example, contractual disputes, environmental issues and other matters. We are not aware of any such matters at December 31, 2016. If new information becomes available, we will establish accruals and/or make disclosures as appropriate.

 

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Credit Risk

The following table presents the percentage of our revenues attributable to our largest customers for the periods indicated:

 

     For the Year Ended
December 31,
 
     2016     2015     2014  

Anadarko and its affiliates — related party

     43     44     30

DCP and its affiliates — related party

     16     23     21

Enbridge and its affiliates — related party

     14     17     23

Enterprise and its affiliates — related party

     19     6     10

Phillips 66 and its affiliates — non-affiliated

     8     8     16

The loss of any of these customers would have a material adverse effect on our financial position, results of operations and cash flows.

 

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