S-1 1 d546480ds1.htm FORM S-1 FORM S-1
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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JUNE 14, 2013

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Midcoast Energy Partners, L.P.

(Exact name of Registrant as Specified in Its Charter)

 

 

 

Delaware   4922   61-1714064

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

(713) 821-2000

(Address, Including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal Executive Offices)

 

 

Chris Kaitson

Vice President—Law and Assistant Secretary

1100 Louisiana Street, Suite 3300

Houston, Texas 77002

(713) 821-2000

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

 

William N. Finnegan IV

Brett E. Braden

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

 

Joshua Davidson

Tull R. Florey

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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    x   (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

 

Proposed

Maximum

Aggregate

Offering Price(1)(2)

  Amount of
Registration Fee

Common units representing limited partner interests

  $575,000,000   $78,430

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933.

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

Subject to Completion

Preliminary Prospectus dated June 14, 2013

PROSPECTUS

Common Units

Representing Limited Partner Interests

Midcoast Energy Partners, L.P.

 

 

This is an initial public offering of common units representing limited partner interests of Midcoast Energy Partners, L.P. We are offering              common units in this offering. We expect that the initial public offering price will be between $         and $         per common unit. We were recently formed by Enbridge Energy Partners, L.P., and no public market currently exists for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “MEP.”

Investing in our common units involves a high degree of risk. Before buying any common units, you should carefully read the discussion of risks of investing in our common units in “Risk Factors” beginning on page 21. These risks include the following:

 

 

We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution, or any distribution, to our unitholders.

 

 

Our financial performance could be adversely affected if our assets are used less. Any decrease in the volumes of natural gas or natural gas liquids, 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 flow.

 

 

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.

 

 

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.

 

 

Enbridge Energy Partners, L.P. 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. Enbridge Energy Partners, L.P. 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.

 

 

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common and subordinated units with contractual standards governing its duties.

 

 

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

 

 

Unitholders have very limited voting rights and even if they are dissatisfied they currently cannot remove our general partner without its consent.

 

 

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service 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, then our distributable cash flow to our unitholders would be substantially reduced.

 

 

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.

 

 

 

      

Per Common Unit

    

Total

 

Initial public offering price

     $                          $          

Underwriting discounts and commissions(1)

     $                          $     

Proceeds to Midcoast Energy Partners, L.P., before expenses

     $                          $     

 

  (1) Excludes a structuring fee equal to     % of the gross proceeds of this offering payable to Merrill Lynch, Pierce, Fenner & Smith Incorporated. Please read “Underwriting.”

The underwriters may also purchase up to an additional              common units from us at the public offering price, less the underwriting discounts and commissions, within 30 days from the date of this prospectus.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Delivery of the common units is expected to be made on or about                     , 2013.

 

 

BofA Merrill Lynch

 

 

The date of this prospectus is                     , 2013


Table of Contents

 

LOGO


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

Overview

     1   

Reasons for the Offering

     3   

Our Natural Gas and NGL Midstream Business

     3   

Business Strategies

     6   

Competitive Strengths

     7   

Our Relationship with EEP and Enbridge

     8   

Risk Factors

     8   

The Transactions

     8   

Organizational Structure After the Transactions

     10   

Management of Midcoast Energy Partners, L.P.

     11   

Principal Executive Offices and Internet Address

     11   

Summary of Conflicts of Interest and Duties

     11   

The Offering

     13   

Summary Historical And Pro Forma Consolidated Financial And Operating Data

     18   

RISK FACTORS

     21   

Risks Related to our Business

     21   

Risks Inherent in an Investment in Us

     38   

Tax Risks

     47   

USE OF PROCEEDS

     52   

CAPITALIZATION

     53   

DILUTION

     54   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     55   

General

     55   

Our Minimum Quarterly Distribution

     57   

Unaudited Pro Forma Distributable Cash Flow for the Year Ended December  31, 2012 and the Twelve Months Ended March 31, 2013

     59   

Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2014

     62   

Assumptions and Considerations

     65   

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

     72   

Distributions of Available Cash

     72   

Operating Surplus and Capital Surplus

     73   

Capital Expenditures

     76   

Subordinated Units and Subordination Period

     76   

Distributions of Available Cash From Operating Surplus During the Subordination Period

     78   

Distributions of Available Cash From Operating Surplus After the Subordination Period

     78   

 

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General Partner Interest and Incentive Distribution Rights

     79   

Percentage Allocations of Available Cash from Operating Surplus

     80   

General Partner’s Right to Reset Incentive Distribution Levels

     80   

Distributions from Capital Surplus

     83   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     83   

Distributions of Cash Upon Liquidation

     84   

SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL AND OPERATING DATA

     87   

Non-GAAP Financial Measures

     90   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     93   

Overview

     93   

How We Generate Revenue and Segment Gross Margin

     95   

How We Evaluate Our Operations

     97   

Items Affecting the Comparability of Our Financial Results

     98   

Factors and Trends that Impact Our Business

     99   

Future Growth Opportunities

     101   

Summary of Consolidated Operating Results

     103   

Results of Operations—By Segment

     103   

Liquidity and Capital Resources

     113   

Off Balance Sheet Arrangements

     118   

Quantitative and Qualitative Disclosures About Market Risk

     119   

Recent Accounting Pronouncements

     126   

Critical Accounting Policies and Estimates

     127   

INDUSTRY OVERVIEW

     134   

General

     134   

Market Fundamentals

     137   

BUSINESS

     143   

Overview

     143   

Reasons for the Offering

     144   

Our Natural Gas and NGL Midstream Business

     144   

Business Strategies

     148   

Competitive Strengths

     149   

Our Relationship with EEP and Enbridge

     150   

Gathering, Processing and Transportation

     151   

Logistics and Marketing

     166   

Seasonality

     169   

 

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Table of Contents

Insurance

     169   

Focus on Safety and Integrity

     169   

Pipeline Control Operations

     170   

Rate and Other Regulation

     170   

Sales of Natural Gas, Condensate and NGLs

     174   

Pipeline Safety and Transportation Regulation

     174   

Environmental Regulation

     176   

Title to Properties and Permits

     179   

Employees

     179   

Legal Proceedings

     179   

MANAGEMENT

     180   

Management of Midcoast Energy Partners, L.P.

     180   

Directors and Executive Officers of Midcoast Holdings, L.L.C.

     181   

Board Leadership Structure

     184   

Board Role in Risk Oversight

     184   

Compensation of Our Officers and Directors

     184   

SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     206   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     207   

Distributions and Payments to Our General Partner and Its Affiliates

     207   

Agreements Governing the Transactions

     208   

Procedures for Review, Approval and Ratification of Related Person Transactions

     211   

CONFLICTS OF INTEREST AND DUTIES

     212   

Conflicts of Interest

     212   

Duties of the General Partner

     218   

DESCRIPTION OF THE COMMON UNITS

     222   

The Units

     222   

Transfer Agent and Registrar

     222   

Transfer of Common Units

     222   

OUR PARTNERSHIP AGREEMENT

     224   

Organization and Duration

     224   

Purpose

     224   

Capital Contributions

     224   

Voting Rights

     224   

Limited Liability

     226   

Issuance of Additional Securities

     227   

Amendment of Our Partnership Agreement

     227   

 

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Table of Contents

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

     229   

Termination and Dissolution

     230   

Liquidation and Distribution of Proceeds

     231   

Withdrawal or Removal of Our General Partner

     231   

Transfer of General Partner Interest

     232   

Transfer of Ownership Interests in Our General Partner

     232   

Transfer of Incentive Distribution Rights

     232   

Change of Management Provisions

     233   

Limited Call Right

     233   

Meetings; Voting

     233   

Status as a Limited Partner

     234   

Indemnification

     234   

Reimbursement of Expenses

     235   

Books and Reports

     235   

Right to Inspect Our Books and Records

     235   

Registration Rights

     236   

Exclusive Forum

     236   

UNITS ELIGIBLE FOR FUTURE SALE

     237   

Rule 144

     237   

Our Partnership Agreement and Registration Rights

     237   

Lock-up Agreements

     238   

Registration Statement on Form S-8

     238   

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

     239   

Partnership Status

     240   

Limited Partner Status

     241   

Tax Consequences of Unit Ownership

     241   

Tax Treatment of Operations

     247   

Disposition of Common Units

     248   

Uniformity of Units

     251   

Tax-Exempt Organizations and Other Investors

     251   

Administrative Matters

     252   

Recent Legislative Developments

     255   

State, Local, Foreign and Other Tax Considerations

     256   

INVESTMENT IN MIDCOAST ENERGY PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

     257   

UNDERWRITING

     259   

Commissions and Discounts

     259   

Option to Purchase Additional Common Units

     260   

 

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Directed Unit Program

     260   

No Sale of Similar Securities

     260   

New York Stock Exchange Listing

     261   

Price Stabilization, Short Positions and Penalty Bids

     261   

Electronic Distribution

     262   

FINRA

     262   

Other Relationships

     262   

Notice to Prospective Investors in the European Economic Area

     262   

Notice to Prospective Investors in the United Kingdom

     263   

Notice to Prospective Investors in Switzerland

     264   

Notice to Prospective Investors in Germany

     264   

Notice to Prospective Investors in the Netherlands

     264   

VALIDITY OF THE COMMON UNITS

     265   

EXPERTS

     265   

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     265   

FORWARD-LOOKING STATEMENTS

     266   

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

     F-1   

APPENDIX A: FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF MIDCOAST ENERGY PARTNERS, L.P.

     A-1   

APPENDIX B: GLOSSARY OF TERMS

     B-1   

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with additional information or information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should not assume information contained herein is accurate as of any date other than the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data are also based on our good faith estimates.

 

v


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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. It does not contain all the information you should consider before investing in our common units. You should carefully read the entire prospectus, including “Risk Factors” and the historical and unaudited pro forma consolidated financial statements and related notes included elsewhere in this prospectus before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (1) an initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (2) that the underwriters do not exercise their option to purchase additional common units.

Unless the context otherwise requires, references in this prospectus to “Midcoast Energy Partners,” “our partnership,” “we,” “our,” “us,” or like terms, when used in a historical context, refer to Midcoast Operating, L.P. (formerly known as Enbridge Midcoast Energy, L.P.), our predecessor for accounting purposes, which we sometimes refer to as “our Predecessor.” When used in the present tense or future tense, these terms refer to Midcoast Energy Partners, L.P. and its subsidiaries. References to “our general partner” refer to Midcoast Holdings, L.L.C. References to “Enbridge Energy Partners” or “EEP” refer collectively to Enbridge Energy Partners, L.P. and its subsidiaries, other than us, our subsidiaries and our general partner. References to “Enbridge” refer collectively to Enbridge Inc. and its subsidiaries other than us, our subsidiaries and our general partner and EEP, its subsidiaries and its general partner. References to “Midcoast Operating” refer to Midcoast Operating, L.P. and its subsidiaries. We own a 39% controlling interest in Midcoast Operating and EEP owns a 61% non-controlling interest 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 61% non-controlling interest in Midcoast Operating. We have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

Midcoast Energy Partners, L.P.

Overview

We are a growth-oriented Delaware limited partnership recently 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, or NGL, midstream business in the United States. As a pure-play U.S. natural gas and NGL midstream business, we will be able to pursue a more focused and flexible strategy, have direct access to the equity and debt capital markets, and have the opportunity to grow through organic growth opportunities and acquisitions, including drop-down transactions from EEP.

Our initial assets consist of a 39% controlling interest in Midcoast Operating, a Delaware 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. 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 has retained a 61% non-controlling interest in Midcoast Operating.

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 market natural gas and NGLs to wholesale customers.

 

 

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We seek to provide our customers with best-in-class field-level service and responsiveness using our significant 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.

Midcoast Operating’s primary operating assets include:

 

   

approximately 11,400 miles of natural gas gathering and transportation lines and approximately 222 miles of NGL gathering and transportation lines;

 

   

a 35% interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together are currently constructing a 580-mile, 20-inch NGL intrastate transportation pipeline extending from the Texas Panhandle to Mont Belvieu, Texas and a related NGL gathering system that is expected to initially consist of approximately 116 miles of gathering lines, all of which are expected to be in service by the third quarter of 2013;

 

   

20 active natural gas processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants, with a combined capacity of approximately 2.0 billion cubic feet per day, or Bcf/d, including 350 million cubic feet per day, or MMcf/d, provided by our HCDP plants;

 

   

10 active natural gas treating plants, including three that are leased from third parties, with a total combined capacity of approximately 1.3 Bcf/d;

 

   

approximately 560 compressors with approximately 810,000 aggregate horsepower, the substantial majority of which are owned by Midcoast Operating and the remainder of which are leased from third parties;

 

   

a liquids railcar loading facility near Pampa, Texas, which we refer to as our TexPan liquids railcar facility;

 

   

an approximately 40-mile crude oil pipeline and associated crude oil storage facility near Mayersville, Mississippi, including a crude oil barge loading facility located on the Mississippi River; and

 

   

approximately 250 transport trucks, 300 trailers and 166 railcars for transporting NGLs.

The following table sets forth Midcoast Operating’s net income and Adjusted EBITDA, on a 100% basis, for the periods indicated. We own a 39% controlling interest in Midcoast Operating.

 

     Three months ended
March 31, 2013
     Year ended
December 31, 2012
 
     (in millions)  

Net income

   $ 30.7       $ 167.5   

Adjusted EBITDA

   $ 67.9       $ 305.1   

Please read “Selected Historical and Pro Forma Consolidated Financial and Operating Data—Non-GAAP Financial Measures—Adjusted EBITDA” for our definition of Adjusted EBITDA and our reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America, or U.S. GAAP.

 

 

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Reasons for the Offering

EEP has indicated that it intends for us to serve as its primary vehicle for owning and growing its U.S. natural gas and NGL midstream business, while it retains 100% ownership of its crude oil and liquid petroleum midstream business. The reason for this restructuring of EEP’s business is to accomplish the following strategic objectives:

 

   

Enhances Strategic Focus of Each Partnership. By separating its midstream businesses into two separate partnerships, we and EEP will each be able to pursue a more focused strategy, leaving us better able to pursue value creation strategies in the natural gas and NGL midstream business and leaving EEP better positioned to develop its crude oil and liquid petroleum midstream business.

 

   

Increases Ability to Respond to Market Opportunities. The separation allows each partnership to focus its resources on its respective operations, customers and core businesses, with greater ability to anticipate, respond rapidly to and pursue opportunities that arise from changing market dynamics.

 

   

Creates More Efficient Capital Structures. Both partnerships will have direct access to the equity and debt capital markets to fund their respective growth strategies and to establish the optimal capital structure for their specific business needs.

 

   

Creates Drop-Down Opportunities. EEP has indicated that it intends, but is not obligated, to sell its remaining ownership interest in Midcoast Operating to us in a series of drop-down transactions over the next four to five years in order to raise capital to develop its crude oil and liquid petroleum midstream business.

 

   

Creates Increased Investor Choice. By forming us, EEP is providing investors with two investment vehicles for its midstream assets, each with its own unique growth strategy, risk profile, capital structure and financial prospects.

Our Natural Gas and NGL Midstream Business

We conduct our business through two distinct reporting segments: gathering, processing and transportation and logistics and marketing.

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 and NGL fractionation facilities. 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, when the Texas Express NGL system commences service, which is expected to occur during the third quarter of 2013, we will gather NGLs from certain of our facilities for delivery on the Texas Express NGL mainline to Mont Belvieu, Texas. Our gathering, processing and transportation business comprised approximately 89% of our gross margin for each of the year ended December 31, 2012 and the three months ended March 31, 2013.

 

 

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Our gathering, processing and transportation business consists of the following four systems:

 

   

Anadarko system: Approximately 2,950 miles of natural gas gathering and transportation pipelines, approximately 54 miles of NGL pipelines, eight active natural gas processing plants, three standby natural gas processing plants and one standby treating plant located in the Anadarko basin. For the three months ended March 31, 2013, this system had average daily volumes of approximately 964,000 MMBtu/d of natural gas.

 

   

East Texas system: Approximately 3,850 miles of natural gas gathering and transportation pipelines, approximately 108 miles of NGL pipelines, six active natural gas processing plants, including two HCDP plants, 10 active natural gas treating plants, one standby natural gas treating plant and one fractionation facility located in the East Texas basin. For the three months ended March 31, 2013, this system had average daily volumes of approximately 1,252,000 MMBtu/d of natural gas.

 

   

North Texas system: Approximately 4,600 miles of natural gas gathering and transportation pipelines, approximately 60 miles of NGL pipelines, six active natural gas processing plants and one standby natural gas processing plant located in the Fort Worth basin. For the three months ended March 31, 2013, this system had average daily volumes of approximately 332,000 MMBtu/d of natural gas.

 

   

Texas Express NGL system: A 35% interest in an approximately 580-mile NGL intrastate transportation mainline and a related NGL gathering system that will initially consist of approximately 116 miles of gathering lines. Both the mainline and the gathering system are currently being constructed and are expected to commence service during the third quarter of 2013. The mainline is expected to have an initial capacity of approximately 280,000 Bpd and, upon completion, will serve as a link between growing supply sources of NGLs in the Anadarko and Permian basins and the Mid-Continent and Rockies regions of the United States and the primary demand markets on the U.S. Gulf Coast.

The following table sets forth certain operating information for the processing and treating facilities included in our gathering, processing and transportation business as of and for the three months ended March 31, 2013:

 

Asset

  

Average
Daily
Volumes
(MMBtu/d)

    

Aggregate
Processing
Capacity

(MMcf/d)

    

Aggregate
Treating
Capacity

(MMcf/d)

   

Compression

(Horsepower)

    

Wells
Connected(1)

 

Anadarko system

     964,000         965         150        442,000         3,600   

East Texas system

     1,252,000         735         1,335 (2)      198,000         5,600   

North Texas system

     332,000         275         —          170,000         3,400   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

Total

     2,548,000         1,975         1,485        810,000         12,600   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) Represents the approximate number of wells directly connected to our systems and our estimate of the number of wells connected to central receipt points on our systems.
(2) Includes three treating plants leased from third parties with a combined treating capacity of approximately 220 MMcf/d of natural gas.

For the three months ended March 31, 2013, we produced an average of approximately 88,500 Bpd of NGLs.

 

 

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Logistics and Marketing

The primary role of our logistics and marketing business is to market 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, such as distributors, refiners, fractionators, utilities, chemical facilities and power plants. Our logistics and marketing business comprised approximately 11% of our gross margin for each of the year ended December 31, 2012 and the three months ended March 31, 2013.

The following table sets forth the volumes of natural gas, NGLs and crude oil sold by our logistics and marketing business for the three months ended March 31, 2013:

 

Volumes of products sold

  

Three months ended
March 31, 2013

 

Natural gas (MMBtu/d)

     1,352,951   

NGLs (Bpd)

     164,108   

Crude oil (Bpd)

     29,693   

The physical assets of our logistics and marketing business primarily consist of:

 

   

approximately 250 transport trucks, 300 trailers and 166 railcars for transporting NGLs;

 

   

our TexPan liquids railcar facility near Pampa, Texas; and

 

   

an approximately 40-mile crude oil pipeline and associated crude oil storage facility near Mayersville, Mississippi, including a crude oil barge loading facility located on the Mississippi River.

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 of firm NGL fractionation capacity;

 

   

approximately 2.5 Bcf of firm natural gas storage capacity;

 

   

up to approximately 120,000 Bpd of firm NGL transportation capacity on the Texas Express NGL system;

 

   

up to approximately 89,000 Bpd of additional NGL transportation capacity, a significant portion of which is firm capacity, through transportation and exchange agreements with four NGL pipeline transportation companies; and

 

   

approximately 5.0 MMBbls of firm NGL storage capacity.

The activities conducted by our logistics and marketing business are primarily conducted within the states of Texas, Louisiana, Oklahoma, Kansas and Mississippi. Our logistics and marketing business also allows us to deploy transportation assets to emerging resource plays to service our customers’ immediate transportation needs, as well as to attract new customers for our gathering, processing and transportation business.

 

 

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Business Strategies

Our principal financial objective is 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. Our plan for executing this objective includes the following key business strategies:

 

   

Maintain safe and reliable operations. 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.

 

   

Pursuing accretive acquisitions from EEP and third parties. We intend to pursue acquisitions of additional interests in Midcoast Operating from EEP, as well as accretive acquisitions of complementary assets from third parties. EEP has indicated that it intends to offer us the opportunity to purchase additional interests in Midcoast Operating from time to time, although EEP is not legally obligated to do so. In addition, in conjunction with EEP, we monitor the marketplace to identify and pursue acquisitions from third parties that complement or diversify our existing operations.

 

   

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 management team’s 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/or maximize throughput volumes.

 

   

Enhancing the profitability of our existing assets. To address the increasing producer focus on the liquids portion of the midstream natural gas value chain, we expect to continue to increase our natural gas processing capacity, NGL takeaway capacity options, and our third party fractionation alternatives. We seek to capitalize on opportunities to attract new customers, increase volumes of natural gas and NGLs that we gather, transport, process or treat and otherwise enhance utilization and operating efficiencies, including increasing customer access to preferred natural gas and NGL markets. We believe our approach will provide our customers with greater value for their commodities and increase the utilization of our natural gas and NGL systems.

 

   

Maintaining a conservative and flexible capital structure and targeting investment grade credit metrics in order to lower our overall cost of capital. We intend to maintain a balanced capital structure that should afford us access to the capital markets at a competitive cost of capital. Although we do not currently have a credit rating, we plan to target debt-to-EBITDA, EBITDA-to-interest and other key credit metrics that are consistent with investment grade businesses in our industry.

 

 

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Competitive Strengths

We believe that the following competitive strengths position us to successfully execute our business strategies:

 

   

Large-scale, strategically located assets in prolific natural gas-producing basins with unconventional resource plays and access to major market hubs. Our large-scale natural gas gathering, treating, processing and transportation system assets are primarily located in Texas and Oklahoma and are strategically positioned within core areas of established, proven and prolific natural gas-producing basins with multiple producing formations, including unconventional resource plays, and significant access to major market hubs for natural gas and NGLs. We believe that producers will continue their drilling and completion activities in these core areas even if natural gas prices do not increase significantly from current levels because the return economics associated with core-area wells remain favorable in lower pricing environments compared to more marginal areas of production.

 

   

Balanced contract mix and hedging policy to optimize profitability. Approximately one-half of the segment gross margin of our gathering, processing and transportation business is generated from fee-based revenues, including demand charges. The remaining portion is generated from contracts with varying degrees of commodity price exposure, which will benefit us in increasing commodity price environments but reduce our profitability in decreasing commodity price environments. We seek to mitigate our downside to direct commodity exposure by employing a prudent hedging strategy. We believe that our contract mix, combined with our hedging strategy, allows us to optimize our profitability over time by allowing us to take advantage of higher commodity price environments and mitigating our downside exposure in lower commodity price environments.

 

   

Affiliation with EEP and Enbridge, leaders in midstream energy infrastructure. We believe that we will benefit from EEP’s and Enbridge’s operational expertise and extensive industry knowledge, as well as their expertise in project development, asset acquisition and asset integration. As a result of its significant ownership interest in us and Midcoast Operating, EEP will have a vested interest in our success and we expect that EEP will be incentivized to support our growth and development to enhance the value of our business, including by offering us the ability to purchase additional interests in Midcoast Operating.

 

   

Integrated solutions across the midstream value chain. We provide our customers with services at multiple stages in the midstream value chain, including gathering, compression, treating, dehydration, processing, stabilization, transportation, fractionation, logistics and marketing services. We believe our ability to provide our natural gas customers with a single source that satisfies their needs from the wellhead to market, combined with our commitment to superior customer service, will allow us to continue to cultivate valuable and stable customer relationships over the long term. Additionally, we believe that actively participating in these midstream segments affords us greater market insight and the ability to quickly respond to and take advantage of changing market dynamics.

 

   

Experienced operational and management team. Our engineering, construction, commercial, logistics and operations teams have significant experience in designing, constructing and operating large-scale midstream energy assets. In addition, our executive management team has an average of approximately 25 years of energy industry experience and a proven track record of operating natural gas and NGL assets, as well as identifying and executing both organic growth projects and third-party acquisitions. Because of our relationship with EEP and Enbridge, we also will have access to a significant pool of management talent and technical expertise and strong commercial relationships throughout the energy industry.

 

 

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Our Relationship with EEP and Enbridge

We believe one of our primary strengths is our affiliation with EEP and Enbridge. We were formed to be EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. EEP has expressed its intent to focus its efforts on its crude oil and liquid petroleum midstream business and intends for us to be a pure-play natural gas and NGL midstream partnership.

Following the completion of this offering, EEP will continue to own crude oil and liquid petroleum assets and a 61% non-controlling interest in Midcoast Operating. EEP will also retain a significant interest in us through its ownership of our general partner, a     % limited partner interest in us and all of our incentive distribution rights. Given EEP’s significant ownership interest in us following this offering and its intent to use us to own and grow its natural gas and NGL midstream business in the United States, we believe EEP will promote and support the successful execution of our business strategies and that EEP will be incentivized to offer us the opportunity to purchase additional interests in Midcoast Operating. However, EEP is under no obligation to offer to sell us additional interests in Midcoast Operating, and we are under no obligation to buy any such additional interests. EEP’s common units trade on the New York Stock Exchange, or NYSE, under the ticker symbol “EEP.” EEP is a Fortune 500 company and had a total market capitalization of $9.1 billion as of March 31, 2013.

The general partner of EEP is owned by Enbridge. Enbridge and its predecessors have been a transporter of energy since the late 1940s. Enbridge’s common stock trades on the NYSE in the United States and the Toronto Stock Exchange in Canada under the ticker symbol “ENB.” As of March 31, 2013, Enbridge had a total market capitalization of $37.7 billion. Through our affiliation with EEP and its affiliation with Enbridge, we expect to have access to a significant pool of management talent and technical expertise and strong commercial relationships throughout the energy industry. Enbridge employs over 10,000 people in the United States and Canada.

In connection with the closing of this offering, Midcoast Operating will enter into a financial support agreement with EEP pursuant to which, during the term of the agreement, EEP will guarantee Midcoast Operating’s financial obligations under derivative agreements and natural gas and NGL purchase agreements, and we will enter into an intercorporate services agreement with EEP pursuant to which we will agree upon certain aspects of our relationship with EEP, including the provision by EEP or its affiliates to us of certain administrative services and employees, our agreement to reimburse EEP or its affiliates for the cost of such services and employees and certain other matters. Please read “Certain Relationships and Related Party Transactions.” While we believe our affiliation with EEP and Enbridge is a positive attribute, it can also be a source of conflicts. For example, neither EEP nor Enbridge is restricted in its ability to compete with us and, in certain instances, may decide to favor its own interests over ours. Please read “Conflicts of Interest and Duties.”

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” and the other information in this prospectus before investing in our common units.

The Transactions

We were formed in May 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. In connection with this offering, EEP will contribute to us a 38.999% limited partner interest in Midcoast Operating and a 100% interest in Midcoast OLP GP, L.L.C. (formerly known as Enbridge Midcoast Holdings, L.L.C.), the general partner of Midcoast Operating, which owns a 0.001% general partner interest in Midcoast Operating.

 

 

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Additionally, at or prior to the closing of this offering, the following transactions will occur:

 

   

we will issue              common units and              subordinated units to EEP, representing an aggregate     % limited partner interest in us, and              general partner units, representing a 2% general partner interest in us, and all of our incentive distribution rights to our general partner;

 

   

we will issue              common units to the public in this offering, representing a     % limited partner interest in us, and will apply the net proceeds as described in “Use of Proceeds”;

 

   

we will enter into a new $         million revolving credit facility;

 

   

we will borrow $350.0 million under our revolving credit facility to distribute to EEP in partial consideration of its contribution of assets to us;

 

   

we will enter into an intercorporate services agreement with EEP; and

 

   

Midcoast Operating will enter into a financial support agreement with EEP under which, during the term of the agreement, EEP will guarantee Midcoast Operating’s financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating is a party.

 

 

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Organizational Structure After the Transactions

The following simplified diagram depicts our organizational structure after giving effect to the transactions described above under “—The Transactions,” assuming the underwriters’ option to purchase additional common units from us is not exercised.

 

LOGO

 

 

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After giving effect to the transactions described above under “—The Transactions,” assuming the underwriters’ option to purchase additional common units from us is not exercised, our units will be held as follows:

 

Public common units

         

EEP common units

         

EEP subordinated units

         

General partner units

     2
  

 

 

 

Total

     100
  

 

 

 

Management of Midcoast Energy Partners, L.P.

We are managed and operated by the board of directors and executive officers of Midcoast Holdings, L.L.C., our general partner. EEP is the sole owner of our general partner and has the right to appoint the entire board of directors of our general partner, including the independent directors appointed in accordance with the listing standards of the NYSE. Through a delegation of control agreement, EEP’s general partner has delegated to Enbridge Energy Management, L.L.C., or Enbridge Management, the authority to manage and control EEP’s business and affairs. Through its indirect ownership of Enbridge Management’s voting shares, Enbridge controls Enbridge Management and appoints all of its directors. Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. Many of the executive officers and directors of our general partner also currently serve as executive officers of Enbridge Management and of EEP’s general partner. For more information about the directors and executive officers of our general partner, please read “Management—Directors and Executive Officers of Midcoast Holdings, L.L.C.”

In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, Midcoast Operating, which will conduct its operations through various operating subsidiaries. However, neither we nor our subsidiaries will have any employees. Our general partner is responsible for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by affiliates of EEP. All of the personnel that will conduct our business immediately following the closing of this offering will be employed or contracted by our general partner and its affiliates, but we sometimes refer to these individuals in this prospectus as our employees because they provide services directly to us. Please read “Management.”

Principal Executive Offices and Internet Address

Our principal executive offices are located at 1100 Louisiana Street, Suite 3300, Houston, Texas 77002, and our telephone number is (713) 821-2000. Following the completion of this offering, our website will be located at www.             .com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership. However, because our general partner is a wholly owned subsidiary of EEP, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner that they believe is in the best interests of EEP. As a result of this relationship, conflicts of

 

 

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interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including EEP, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of our common units, which in turn has an effect on whether our general partner receives incentive cash distributions. In addition, our general partner may determine to manage our business in a way that directly benefits EEP’s businesses, rather than indirectly benefitting EEP solely through its ownership interests in us. All of these actions are permitted under our partnership agreement and will not be a breach of any duty (fiduciary or otherwise) of our general partner. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Duties.”

Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including EEP and Enbridge, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser is deemed to have agreed to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units is deemed to have consented to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—Duties of the General Partner” for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units and subordinated units. For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

 

 

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THE OFFERING

 

Common units offered to the public

             common units.

 

               common units if the underwriters exercise in full their option to purchase additional common units from us.

 

Units outstanding after this offering

             common units and              subordinated units, each representing a             % limited partner interest in us. The general partner will own              general partner units, representing a 2% general partner interest in us.

 

Use of proceeds

We expect to receive net proceeds of approximately $         million from the sale of common units offered by this prospectus based on the assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, the structuring fee and estimated offering expenses. We intend to use the net proceeds as follows:

 

   

approximately $         million will be distributed to EEP;

 

   

$         million will be used to pay revolving credit facility origination and commitment fees; and

 

   

the remainder will be retained by us for general partnership purposes, including to fund our working capital needs.

 

  At the closing of this offering, we will borrow $350.0 million under our revolving credit facility, all of which will be used to fund an additional cash distribution to EEP. The cash distributions to EEP from the proceeds of this offering and the borrowing under our revolving credit facility will be made in consideration of EEP’s contribution of assets to us and to reimburse EEP for certain capital expenditures incurred with respect to those assets. We are funding these distributions through a combination of net proceeds from this offering and borrowings under our revolving credit facility in order to optimize our capital structure.

 

  If the underwriters exercise in full their option to purchase additional common units from us, we expect to receive additional net proceeds of approximately $         million. The net proceeds from any exercise by the underwriters of their option to purchase additional common units from us will be used to redeem from EEP a number of common units equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee. Please read “Underwriting.”

 

 

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Cash distributions

We intend to make a minimum quarterly distribution of $         per unit ($         per unit on an annualized basis) to the extent we have sufficient cash at the end of each quarter after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash.” Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.”

 

  For the quarter in which this offering closes, we will make a prorated distribution on our units covering the period from the completion of this offering through                     , 2013 based on the actual length of that period.

 

  In general, we will pay any cash distributions we make each quarter in the following manner:

 

   

first, 98% to the holders of our common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $         plus any arrearages from prior quarters;

 

   

second, 98% to the holders of our subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $         ; and

 

   

third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $        .

 

  If cash distributions to our unitholders exceed $         per unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

 

  If we do not have sufficient available cash at the end of each quarter, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

 

 

Pro forma distributable cash flow that was generated during the year ended December 31, 2012 and the twelve months ended March 31, 2013, was approximately $86.4 million and $88.7 million, respectively. The amount of distributable cash flow we must generate to support the payment of the minimum quarterly distribution for four

 

 

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quarters on our common units and subordinated units to be outstanding immediately after this offering and the corresponding distributions on our general partner’s 2% interest is approximately $         million (or an average of approximately $         million per quarter). As a result, for the year ended December 31, 2012 and the twelve months ended March 31, 2013, on a pro forma basis, we would have generated sufficient distributable cash flow to support the payment of the aggregate annualized minimum quarterly distribution on all of our common units and subordinated units and the corresponding distributions on our general partner’s 2% interest during those periods. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012 and the Twelve Months Ended March 31, 2013.”

 

  We believe that, based on our financial forecast and related assumptions included in “Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2014,” we will generate sufficient distributable cash flow to support the payment of the aggregate minimum quarterly distribution of $         million on all of our common units and subordinated units and the corresponding distributions on our general partner’s 2% interest for the twelve months ending June 30, 2014. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement, and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read “Risk Factors” and “Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

EEP will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that for any quarter during the subordination period, holders of the subordinated units will not be entitled to receive any distribution until holders of the common units have 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 will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will begin on the closing date of this offering and will extend until the first business day following the date that we have earned and paid distributions of at least (1) $         (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                     , 2016, or (2) $         (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                     , 2014, in

 

 

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each case provided there are no arrearages in payment of the minimum quarterly distributions on our common units at that time.

 

  The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of our subordinated units or their affiliates are voted in favor of that removal.

 

  When the subordination period ends, the outstanding subordinated units will convert into a new class of common units on a one-for-one basis, and all common units will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units, including units senior to the common units, without the approval of our unitholders. Holders of our common and subordinated units will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. Please read “Units Eligible for Future Sale” and “Our Partnership Agreement—Issuance of Additional Securities.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, EEP will own approximately                 % of our common units and subordinated units on a combined basis (or     % of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). This will initially give EEP the ability to prevent the removal of our general partner. Please read “Our Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date that is three business days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. Please read “Our Partnership Agreement—Limited Call Right.”

 

 

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Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2016, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $         per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $         per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. For each taxable year during which the subordinated units and/or a new class of common units into which the subordinated units are converted are outstanding, items of gross income, which would otherwise be allocated to the holders of our subordinated units or new class of common units, will be specially allocated to the holders of the class of common units held by the public in an amount not to exceed the amount that would result in a purchaser of common units in this offering being allocated an amount of federal taxable income for such year that exceeds 20% of the cash distributed with respect to such year. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions” for the basis of this estimate and a discussion of this special gross income allocation.

 

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences.”

 

Directed unit program

At our request, the underwriters have reserved for sale, at the initial public offering price, up to              common units offered by this prospectus for sale to some of the directors, officers, employees, business associates and related persons of our general partner and its affiliates. If these persons purchase reserved common units, the purchased units will be subject to the lock-up restrictions described in “Underwriting—No Sale of Similar Securities” and the purchased units will reduce the number of common units available for sale to the general public. Any reserved common units that are not so purchased will be offered by the underwriters to the general public on the same terms as the other common units offered by this prospectus. Please read “Underwriting—Directed Unit Program.”

 

Exchange listing

We intend to apply to list our common units on the New York Stock Exchange under the symbol “MEP.”

 

 

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SUMMARY HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL

AND OPERATING DATA

The following table shows summary historical consolidated financial and operating data of Midcoast Operating, L.P., our predecessor for accounting purposes, or our Predecessor, and summary pro forma consolidated financial data of Midcoast Energy Partners, L.P. for the periods and as of the dates indicated. The following summary historical consolidated financial and operating data of our Predecessor consists of all of the assets and operations of Midcoast Operating on a 100% basis. In connection with the closing of this offering, EEP will contribute to us a 39% controlling interest in Midcoast Operating. However, as required by U.S. GAAP, we will continue to consolidate 100% of the assets and operations of Midcoast Operating in our financial statements.

The summary historical consolidated financial data of our Predecessor as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010 are derived from the audited consolidated financial statements of our Predecessor appearing elsewhere in this prospectus. The summary historical interim consolidated financial data of our Predecessor as of March 31, 2013 and for the three months ended March 31, 2013 and 2012 are derived from the unaudited interim consolidated financial statements of our Predecessor appearing elsewhere in this prospectus. The following tables should be read together with, and are qualified in their entirety by reference to, the historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The summary pro forma consolidated financial data presented in the following table for the year ended December 31, 2012 and as of and for the three months ended March 31, 2013 are derived from the unaudited pro forma consolidated financial statements included elsewhere in this prospectus. The unaudited pro forma consolidated statement of financial position assumes the offering and the related transactions occurred as of March 31, 2013, and the unaudited pro forma consolidated statements of operations for the year ended December 31, 2012 and the three months ended March 31, 2013 assumes the offering and the related transactions occurred as of January 1, 2012.

The unaudited pro forma consolidated financial statements give effect to the following:

 

   

EEP’s contribution to us of a 38.999% limited partner interest in Midcoast Operating and a 100% member interest in Midcoast OLP GP, L.L.C., which owns a 0.001% general partner interest in Midcoast Operating;

 

   

our issuance of              common units and             subordinated units, representing an aggregate     % limited partner interest in us, to EEP;

 

   

our issuance of              general partner units, representing a 2% general partner interest in us, and all of our incentive distribution rights to our general partner;

 

   

our issuance of              common units, representing a              % limited partner interest in us, to the public in connection with this offering, and our receipt of $         in net proceeds from this offering;

 

   

our entry into a new $         million revolving credit facility and the borrowing of $350.0 million thereunder;

 

   

the application of the proceeds of this offering, together with the proceeds from the borrowings under our revolving credit facility, as described in “Use of Proceeds”; and

 

   

our entry into an intercorporate services agreement with EEP and its affiliates, which includes a $25.0 million annual reduction in the total general and administrative expenses that otherwise would have been fully allocable to us by EEP and its affiliates.

 

 

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The unaudited pro forma consolidated financial statements do not give effect to an estimated $4.0 million of incremental general and administrative expenses that we expect to incur annually as a result of being a separate publicly traded partnership. In addition, the unaudited pro forma consolidated financial statements do not give effect to Midcoast Operating’s entry into a financial support agreement with EEP under which, during the term of the agreement, EEP will guarantee Midcoast Operating’s obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating is a party. Under the financial support agreement, EEP’s guarantee of Midcoast Operating’s obligations will terminate as of the earlier to occur of (1) the fourth anniversary of the closing of this offering and (2) the date on which EEP no longer owns at least a 20% interest in Midcoast Operating. The annual costs Midcoast Operating will incur under the financial support agreement, which we estimate will initially be approximately $5.0 million, will be based on the cumulative average annual amount of letters of credit and guarantees that EEP will provide on Midcoast Operating’s behalf. Based on our 39% controlling interest in Midcoast Operating, we estimate that our proportionate share of these annual expenses will initially be approximately $2.0 million.

The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in evaluating the performance of our business. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with U.S. GAAP, please read “Selected Historical and Pro Forma Consolidated Financial and Operating Data—Non-GAAP Financial Measures.”

 

    Midcoast Operating, L.P. Predecessor Historical     Midcoast Energy
Partners, L.P. Pro Forma
 
    Year ended December 31,     Three months
ended March 31,
    Year ended
December 31,
    Three months
ended

March 31,
 
    2012     2011     2010     2013     2012     2012     2013  
    (in millions, except per unit data)  

Income Statement Data(1):

             

Operating revenues

  $ 5,357.9      $ 7,828.2      $ 6,654.3      $ 1,370.3      $ 1,495.9      $ 5,357.9      $ 1,370.3   

Operating expenses

    5,186.5        7,608.9        6,497.3        1,339.2        1,458.0        5,161.5        1,332.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    171.4        219.3        157.0        31.1        37.9        196.4        37.4   

Interest expense

    —          —          —          —          —          11.0        2.8   

Other income (expense)

    (0.1     2.8        3.0        0.1        (0.1     (0.1     0.1   

Income tax expense

    3.8        2.9        2.6        0.5        0.6        3.8        0.5   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

  $ 167.5      $ 219.2      $ 157.4      $ 30.7      $ 37.2      $ 181.5      $ 34.2   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to Midcoast Energy Partners, L.P

            $ 64.1      $ 11.6   
           

 

 

   

 

 

 

General partner interest in net income attributable to Midcoast Energy Partners, L.P.

             

Limited partner interest in net income attributable to Midcoast Energy Partners, L.P.:

             

Common units

             

Subordinated units

             

Net income per limited partner unit (basic and diluted):

             

Common units

             

Subordinated units

             

Financial Position Data (at period end)(1):

             

Property, plant and equipment, net

  $ 3,963.0      $ 3,651.3      $ 3,320.6      $ 3,991.1          $ 3,991.1   

Total assets

    5,667.4        5,134.6        4,802.6        5,613.9            5,617.7   

Long-term debt(2)

    —          —          —          —              350.0   

 

footnotes on following page

 

 

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    Midcoast Operating, L.P. Predecessor Historical     Midcoast Energy
Partners, L.P. Pro Forma
 
    Year ended December 31,     Three months
ended March 31,
    Year ended
December 31,
    Three months
ended

March 31,
 
    2012     2011     2010     2013     2012     2012     2013  
    (in millions, except per unit data)  

Cash Flow Data(1):

             

Cash flows provided by operating activities

  $ 352.7      $ 415.6      $ 172.4      $ 109.3      $ 142.3       

Cash flows used in investing activities

    (614.5     (480.1     (984.1     (111.8     (141.1    

Cash flows provided by financing activities

    261.8        64.5        811.7        2.5        (1.2    

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

    (621.1     (484.0     (1,002.2     (108.6     (144.3    

Other Financial Data:

             

Adjusted EBITDA(3)

  $ 305.1      $ 348.3      $ 294.8      $ 67.9      $ 69.0      $ 330.1      $ 74.2   

Adjusted EBITDA attributable to Midcoast Energy Partners, L.P.(4)

            $ 128.9      $ 29.0   

 

(1) Our income statement, financial position and cash flow data reflect several significant acquisitions and dispositions. Please read “Selected Historical and Pro Forma Consolidated Financial and Operating Data.”
(2) Represents $350.0 million we expect to borrow at the closing of this offering under a newly established $         million revolving credit facility and remit to EEP as consideration for a portion of the 39% controlling interest in Midcoast Operating contributed to us.
(3) For a discussion of the non-GAAP financial measure of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our most directly comparable measure calculated and presented in accordance with U.S. GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”
(4) Represents Adjusted EBITDA attributable to our 39% controlling interest in Midcoast Operating.

 

    Midcoast Operating, L.P. Predecessor Historical      Midcoast Energy
Partners, L.P. Pro Forma
 
    Year ended December 31,     Three months
ended March 31,
     Year ended
December 31,
    Three months
ended

March 31,
 
    2012     2011     2010     2013     2012      2012     2013  

Operating Statistics:

              

Throughput (MMBtu/d)

              

Anadarko

    1,017,000        1,013,000        711,000        964,000        942,000         1,017,000        964,000   

East Texas

    1,266,000        1,378,000        1,259,000        1,252,000        1,319,000         1,266,000        1,252,000   

North Texas

    330,000        337,000        356,000        332,000        315,000         330,000        332,000   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Total

    2,613,000        2,728,000        2,326,000        2,548,000        2,576,000         2,613,000        2,548,000   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

NGL Production (Bpd)

    97,428        87,376        73,647        88,498        87,411         97,428        88,498   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

 

 

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RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose part or all of your investment.

Risks Related to our Business

We may not generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution, or any distribution, to our unitholders.

In order to support the payment of the minimum quarterly distribution of $         per unit per quarter, or $         per unit on an annualized basis, we must generate distributable cash flow of approximately $         million per quarter, or approximately $         million per year, based on the number of common and subordinated units and our general partner interest that will be outstanding immediately after completion of this offering. We may not generate sufficient distributable cash flow each quarter to support the payment of the minimum quarterly distribution. 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 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;

 

   

the market prices of natural gas and NGLs relative to one another, which affects our processing margins;

 

   

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; 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.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying the forecast of distributable cash flow that we include in “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks that could cause our actual distributable cash flow to differ materially from our forecast.

The forecast of distributable cash flow set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations and distributable cash flow for the twelve months ending June 30, 2014. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in “Cash Distribution Policy and Restrictions on Distributions.” Our financial forecast has been prepared by management, and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in gathered, processed, transported, fractionated and sold volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

 

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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:

 

   

environmental or other governmental regulations;

 

   

weather conditions;

 

   

storage levels;

 

   

alternative energy sources;

 

   

decreased demand for natural gas and NGLs;

 

   

fluctuations in commodity prices, including the price of natural gas and NGL prices;

 

   

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 and NGLs 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 (i) the level of successful drilling activity in our areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) 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, U.S. 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.

 

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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. In the past, 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 and 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;

 

   

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.

The prices of natural gas, NGLs and crude oil are inherently volatile, and we expect this volatility will continue. We buy and sell natural gas, NGLs and crude oil in connection with our marketing activities. Our exposure to commodity price volatility is inherent to our natural gas, NGLs and crude oil purchase and resale activities, in addition to our natural gas processing activities. As of March 31, 2013, approximately 60% of our

 

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gross margin was attributable to contracts with some degree of commodity price exposure. In addition, under our keepwhole/wellhead purchase contracts, we have direct exposure to both natural gas and NGL prices because our costs are dependent on the price of natural gas and our revenues are dependent on the price of NGLs.

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. However, because we are not fully hedged, we will continue to have commodity price exposure on the unhedged portion of the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of this unhedged exposure, 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.

Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our future cash flows. 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.

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.

 

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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 to our unitholders.

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.

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:

 

   

mistaken assumptions about future prices, volumes, revenues and costs, future results of operations or expected cost reductions or other synergies expected to be realized;

 

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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 and increase distributions to our unitholders is dependent on our ability to make acquisitions that result in an increase in distributable cash flow. The acquisition component of our growth strategy is based, in large part, on our expectation of ongoing divestitures by EEP of portions of its remaining ownership interest in Midcoast Operating to us over the next four to five years. The consummation and timing of any future acquisitions of these interests will depend upon, among other things, EEP’s willingness to offer these interests for sale to us, our ability to negotiate acceptable purchase agreements with respect to the interests and our ability to obtain financing on acceptable terms, and we can offer no assurance that we will be able to successfully consummate any future acquisition of additional interests in Midcoast Operating. Furthermore, if EEP reduces its ownership interest in us, it may be less willing to sell its remaining ownership interest in Midcoast Operating to us. In addition, there are no restrictions on EEP’s ability to transfer its ownership interest in Midcoast Operating to a third party.

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. In particular, a significant processing contract on our Anadarko system will terminate in the third quarter of 2013. 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.

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

 

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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 EEP’s general partner 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 on our assets, except pipeline assets that are not located at 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 will enter into with EEP, Enbridge and another Enbridge subsidiary.

 

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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. For example, following Hurricane Ike in 2008, the Mont Belvieu fractionation complex was shut down for a period of time due to loss of power. This shut down impacted our ability to process natural gas during the period at certain of our processing plants.

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 those that became prevalent during the recessionary period of 2008 and continued through much of 2010, periodically result in weakness and volatility in the capital markets, which in turn can limit, temporarily or for extended periods, our ability to raise capital through equity or debt 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.

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 incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

At the closing of this offering, we will borrow $350.0 million under our revolving credit facility to partially fund a cash distribution to EEP. Our existing and future level of debt could have important consequences to us, including the following:

 

   

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

 

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our funds available for operations, future business opportunities and cash distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our 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 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.

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 requires 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 benefit costs with respect to our general partner’s employees, our results of operations could be materially and adversely affected.

Restrictions in our new or any future credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.

We intend to enter into a new credit facility in connection with the closing of this offering. Our new credit facility, or any future credit facility we enter into, is likely to limit our ability to, among other things:

 

   

incur or guarantee additional debt;

 

   

make distributions on or redeem or repurchase units;

 

   

make certain investments and acquisitions;

 

   

make capital expenditures;

 

   

incur certain liens or permit them to exist;

 

   

enter into certain types of transactions with affiliates;

 

   

merge or consolidate with another company; and

 

   

transfer, sell or otherwise dispose of all or substantially all of our assets.

Our new or any future credit facility will likely also contain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

 

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The provisions of our new or any future 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. In addition, a failure to comply with the provisions of our new or any future credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

A less than investment grade credit rating, or the termination of Midcoast Operating’s financial support agreement with EEP, could require Midcoast Operating to provide collateral for Midcoast Operating’s hedging liabilities and negatively impact our interest costs and borrowing capacity under our credit facility.

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. At the closing of this offering, Midcoast Operating will enter into a financial support agreement with EEP under which, during the term of the agreement, EEP will guarantee Midcoast Operating’s financial obligations under derivative agreements and natural gas and NGL purchase agreements. Under the financial support agreement, EEP’s guarantee of Midcoast Operating’s obligations will terminate on the earlier to occur of (1) the fourth anniversary of the closing of this offering and (2) the date on which EEP no longer owns at least a 20% 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. Such a development could adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

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 will not have any indebtedness rated by any credit rating agency at the closing of this offering, we may have rated debt in the future. Credit rating agencies will likely 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.

As part of our logistics and marketing activities, we purchase natural gas and NGLs at prices determined by prevailing market conditions. Following our purchase of natural gas and NGLs, we generally resell the natural gas or NGLs at a higher price under a sales contract that is 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;

 

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consumers’ willingness to use other fuels when natural gas or NGL 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 or NGLs on comparable terms; and

 

   

changes in, limitations upon or elimination of the regulatory authorization required for our wholesale sales of natural gas and NGLs in interstate commerce.

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 regulations may expose us to significant costs and liabilities.

Our pipeline, gathering, processing and trucking operations are subject to federal, state and local laws and regulations relating to environmental protection and operational and worker safety. Numerous governmental authorities have the power to enforce compliance with the laws and regulations they administer and permits they issue, often requiring difficult and costly actions. 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 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. 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 non-compliance 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.

 

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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, emit various types 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 reduce emissions of greenhouse gases. 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 EPA’s mandatory greenhouse gas emissions reporting requirements to include petroleum and natural gas systems.

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 Clean Air Act of 1970, as amended, or CAA, that, in general, 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 increase the greenhouse gas emissions threshold that triggers the permitting requirements for major new (and major modifications to existing) stationary sources. Under a phased-in approach, for most purposes, new permitting provisions are required for new facilities that emit 100,000 tons per year or more of carbon dioxide equivalent, or CO2e, and existing facilities making changes that would increase greenhouse gas emissions by 75,000 CO2e. The EPA has also indicated in rulemakings that it may further reduce the current regulatory thresholds for greenhouse gas emissions, making additional sources subject to permitting. On June 26, 2012, in Coalition for Responsible Regulation v. EPA, the U.S. Circuit Court of Appeals for the District of Columbia circuit upheld the bases for the tailoring rule, and ruled that no petitioners had standing to challenge it. On April 18, 2013, the plaintiffs filed a petition for review of that decision by the U.S. Supreme Court.

In addition, more than one-third of the states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap-and-trade programs. Although many of the state-level initiatives have, to date, focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that in the future sources in states where we operate, such as our gas-fired compressors, could become subject to greenhouse gas-related state regulations. Depending on the particular program, we could in the future be required to purchase and surrender emission allowances or otherwise undertake measures to reduce greenhouse gas emissions. Any additional costs or operating restrictions associated with new legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows, in addition to the demand for our services.

Pipeline operations involve numerous risks that may adversely affect our business and financial condition.

Operation of complex pipeline systems, gathering, treating, processing and trucking 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.

 

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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.

Significant portions of our pipeline systems and processing and treating plants have been in service for several decades, which could lead to increased maintenance or repair expenses and downtime associated with our pipelines and processing and treating plants that could have a material adverse effect on our business and operating results.

Significant portions of our pipeline systems and processing and treating plants have been in service for many decades. The age and condition of our pipeline systems could also result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems and plants could adversely affect our financial condition and results of operations and cash flows and our ability to make cash 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 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 sources, 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 to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available in 2014. In addition, on October 20, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act, or CWA, to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities.

On April 17, 2012, the EPA also approved final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. These new rules address 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 flaring until 2015, after which reduced emission (or “green”) completions must be used. The rules also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On April 12, 2013, EPA proposed amendments to the rule which would, among other things, provide additional time for recently constructed, modified or reconstructed storage tanks to install emission controls. These rules may require a number of modifications to our customers’ and our

 

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own operations, including the installation of new equipment to control emissions. 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.

Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. For example, on December 13, 2011, the Texas Railroad Commission 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. We cannot predict whether any other legislation 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 or state level, that 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 and results of operations.

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 Federal Energy Regulatory Commission, or 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 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 Natural Gas Act of 1938, or NGA. 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 Natural Gas Policy Act of 1978, or NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial

 

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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.

Changes in trucking regulations may increase our costs and negatively impact our results of operations.

For the delivery of fuel and other products to our customers, we operate a fleet of specialized trucks and delivery equipment. We are therefore subject to regulation as a motor carrier by the United States Department of Transportation, or DOT, and various state agencies. These federal and state regulatory authorities exercise broad powers, generally governing such activities as the authorization to engage in motor carrier operations, driver licensing and insurance requirements, safety, equipment testing and transportation of hazardous materials. Our trucking operations, including the special modifications we make to our equipment and vehicles to operate in remote, rugged or environmentally sensitive areas, are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, fuel emissions limits, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period and limits on vehicle weight and size and other matters.

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 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 or cyber-attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks and threats, cyber-attacks, escalation of military activity or acts of war 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 or cyber-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. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. Disruption or significant increases 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.

 

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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 oil and gas hedging transactions. These statutory requirements must be implemented through regulations, primarily through rules to be adopted by the Commodity Futures Trading Commission, or the CFTC. The Dodd-Frank Act provisions may change fundamentally the way many swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which many swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. A considerable number of market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants are subject to new reporting and recordkeeping requirements.

The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing some of the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

Depending on the 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 we fail to attract and retain key management personnel.

Our ability to operate our business and implement our strategies will depend on our continued ability 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. We may not be able to continue to employ our senior executives and other key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and other key personnel could have a material adverse effect on our ability to effectively operate our business.

If we do not ensure that our internal control over financial reporting is effective, we may not be able to prevent intentional misconduct, which could also affect our ability to timely and accurately report our financial results. In January 2012, EEP’s management identified a material weakness in internal controls relating to accounting misstatements that resulted from intentional misconduct and collusion by local management responsible for operating Midcoast Operating’s trucking and NGL marketing subsidiary.

As discussed elsewhere in this prospectus, EEP disclosed in its annual report on Form 10-K for the year ended December 31, 2011 that its management had identified a material weakness in its internal control over financial reporting with respect to Midcoast Operating’s trucking and NGL marketing subsidiary. The material

 

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weakness related to intentional misconduct and collusion of local management and staff to circumvent EEP’s internal control policies which resulted in accounting misstatements. EEP disclosed in its annual report for the year ended December 31, 2012 that it had remediated this material weakness, and EEP’s management concluded that EEP maintained effective internal control over financial reporting as of December 31, 2012.

Beginning with the year ending December 31, 2014, our management will be required to provide a report in our annual reports on Form 10-K on the effectiveness of our internal control over financial reporting, among other controls. We and other Enbridge companies maintain systems of disclosure controls and procedures, including internal control over financial reporting, 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 Securities Exchange Act of 1934, as amended, or 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 system of controls is designed to provide reasonable, but not absolute, assurance regarding the reliability and integrity of accounting and financial reporting. A control system, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met.

Given these inherent limitations, we may not be able to anticipate or timely identify intentional misconduct to circumvent our internal controls. Our failure to anticipate or timely identify such misconduct could affect our ability to timely file our quarterly and annual reports with the SEC and would subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business, as well as on the trading price of our common units.

The amount of cash we have available for distribution to holders of our common and subordinated units 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.

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.

Following this offering, EEP, which is controlled by Enbridge Management through a delegation of control agreement with EEP’s general partner, will control our general partner, and appoint 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.

 

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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, the amount of adjusted operating surplus generated in any given period and the ability of the subordinated units to convert into common units.

 

   

Our general partner will determine which costs incurred by it are reimbursable by us.

 

   

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

 

   

Our partnership agreement permits us to classify up to $         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. This cash may be used to fund distributions on our subordinated units or 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.

 

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Our general partner may elect to cause us to issue 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. Please read “Conflicts of Interest and Duties.”

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only              publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units, and affiliates of our general partner will own, directly or indirectly, approximately         % of our common units and subordinated units on a combined basis (excluding common units purchased by directors and officers of our general partner and Enbridge Management under our directed unit program). We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representative of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

   

our quarterly distributions;

 

   

our quarterly or annual earnings or those of other companies in our industry;

 

   

the loss of a large customer;

 

   

announcements by us or our competitors of significant contracts or acquisitions;

 

   

changes in accounting standards, policies, guidance, interpretations or principles;

 

   

general economic conditions;

 

   

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

   

future sales of our common units; and

 

   

other factors described in these “Risk Factors.”

 

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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, and we do not anticipate there being limitations in our new credit facility, on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our common and subordinated 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.

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 generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of our general partner) after the subordination period has ended. At the closing of this offering, affiliates of our general partner will own, directly or indirectly, approximately     % of our outstanding common units and subordinated units on a combined basis (or         % if the underwriters’ option to purchase additional common units is exercised in full) (excluding common units purchased by directors and officers of our general partner and Enbridge Management under our directed unit program). Please read “Our Partnership Agreement—Amendment of Our Partnership Agreement.”

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 distribution on our common units, 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 common unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”

Because our common units will be 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

 

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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 holders of our common and subordinated units 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 common unitholder is deemed to have consented to the provisions in our partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties—Duties of the General Partner.”

Our partnership agreement limits our general partner’s liabilities and the remedies available to holders of our common and subordinated units 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 unitholders 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 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 unitholders 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.

 

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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. Please read “Conflicts of Interest and Duties.”

Our general partner may elect to cause us to issue 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 common 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 (48.0%) 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 common units equal to that number of 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 would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per 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 common units, which 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 our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

 

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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 upon the closing of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. At the closing of this offering, our general partner and its affiliates will own approximately     % of the common units and subordinated units on a combined basis (or     % if the underwriters’ option to purchase additional common units is exercised in full) (excluding common units purchased by directors and officers of our general partner and Enbridge Management under our directed unit program). Also, if our general partner is removed without cause (as defined under our partnership agreement) during the subordination period and common units and subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

“Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units into common units.

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 common and subordinated 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 a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

   

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 units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the completion of this offering, EEP will hold              common units and              subordinated units. All of the subordinated units will convert into a new class of common units on a one-for-one basis at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide EEP with certain registration rights under applicable securities laws. Please read “Units Eligible for Future Sale.” The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

 

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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 you to sell your 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 common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of our 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 common units during the 90-day period preceding the date such notice is first mailed. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your 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 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. At the completion of this offering, and assuming the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates will own approximately     % of our common units (excluding common units purchased by directors and officers of our general partner and Enbridge Management under our directed unit program). At the end of the subordination period (which could occur as early as                     , 2014), assuming no additional issuances of common units (other than upon the conversion of the subordinated units) and the underwriters’ option to purchase additional common units from us is not exercised, our general partner and its affiliates (excluding directors and officers of our general partner and Enbridge Management) will own approximately     % of our outstanding common units. For additional information about this limited call right, please read “Our Partnership Agreement—Limited Call Right.”

Your 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. You could be liable for any or all of our obligations as if you 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

 

   

your 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.

Please Read “Our Partnership Agreement—Limited Liability” for a discussion of the limitations of liability on a unitholder.

 

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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 you 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.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management.”

You will experience immediate and substantial dilution in pro forma net tangible book value of $         per common unit.

The assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of this prospectus) exceeds our pro forma net tangible book value of $         per unit. Based on an assumed initial public offering price of $         per common unit, you will incur immediate and substantial dilution of $         per common unit. This dilution results primarily because the assets contributed by EEP are recorded in accordance with U.S. GAAP, at their historical cost, and not their fair value. Please read “Dilution.”

Tax Risks

In addition to reading the following risk factors, please read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service (“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, 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. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a 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.

 

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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. Imposition of any such taxes may substantially reduce the cash we have available for distribution to you. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, 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 or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the impact of that law on us.

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. Please read “Material Federal Income Tax Consequences—Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

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 it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it 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 conclusions of our counsel expressed in this prospectus or from the positions we 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 counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. 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.

 

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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 their allocable share of our net taxable income decreases their tax basis in their 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 it sells such common units at a price greater than its 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. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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 will 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 adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt 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 available to you. Latham & Watkins LLP is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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 will 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 use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, however, the U.S. Treasury Department issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed

 

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regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge this 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. Latham & Watkins LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

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, he 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, he 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. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to ensure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions 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 will 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.

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

 

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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 his 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 recently announced 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. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you 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 initially expect to conduct business in over 35 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 your 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. Please consult your tax advisor.

 

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $         million from the sale of              common units offered by this prospectus, based on an assumed initial public offering price of $         per common unit (the mid-point of the price range set forth on the cover of the prospectus), after deducting underwriting discounts, a structuring fee and estimated offering expenses. Our estimate assumes the underwriters’ option to purchase additional common units from us is not exercised. We intend to use these proceeds as follows:

 

   

approximately $         million will be distributed to EEP;

 

   

$         million will be used to pay revolving credit facility origination and commitment fees; and

 

   

the remainder will be retained by us for general partnership purposes, including to fund our working capital needs.

At the closing of this offering, we will enter into a new $         million revolving credit facility, under which we will borrow $350.0 million to fund an additional $350.0 million cash distribution to EEP. The cash distributions to EEP from the proceeds of this offering and the borrowing under our revolving credit facility will be made in consideration of its contribution of assets to us and to reimburse EEP for certain capital expenditures incurred with respect to those assets. We are funding these distributions through a combination of net proceeds from this offering and borrowings under our revolving credit facility in order to optimize our capital structure.

If the underwriters exercise in full their option to purchase additional common units from us, we expect to receive additional net proceeds of approximately $         million. The net proceeds from any exercise by the underwriters of their option to purchase additional common units from us will be used to redeem from EEP a number of common units equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Underwriting.”

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, the structuring fee and offering expenses, to increase or decrease by $         million.

 

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CAPITALIZATION

The following table shows:

 

   

the historical cash and cash equivalents and capitalization of our Predecessor as of March 31, 2013; and

 

   

our pro forma cash and cash equivalents and capitalization as of March 31, 2013, giving effect to this offering and the related transactions described under “Prospectus Summary—The Transactions” and the application of the net proceeds of this offering in the manner described under “Use of Proceeds.”

This table is derived from, should be read together with, and is qualified in its entirety by reference to, the historical consolidated financial statements and the accompanying notes and the unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of March 31, 2013  
     Historical      Pro forma(1)  
     (in millions)  

Cash and cash equivalents

   $ —         $     
  

 

 

    

 

 

 

Long-term debt:

     

Revolving credit facility

   $ —        $ 350.0   
  

 

 

    

 

 

 

Total long-term debt (including current maturities)

     —           350.0   
  

 

 

    

 

 

 

Net investment/partners’ capital:

     

Net investment

     4,746.7      

Public common units

     —        

EEP-owned common units

     —        

EEP-owned subordinated units

     —        

General partner interest

     —        

Total partners’ capital attributable to Midcoast Energy Partners, L.P.

     4,746.7      
  

 

 

    

Non-controlling interest in Midcoast Operating, L.P.

     —        
  

 

 

    

 

 

 

Total investment/partners’ capital

     4,746.7      
  

 

 

    

 

 

 

Total capitalization

   $ 4,746.7       $     
  

 

 

    

 

 

 

 

(1) Assumes the mid-point of the price range set forth on the cover of this prospectus.

 

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DILUTION

Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of                     , 2013, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $         million, or $         per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

 

Assumed initial public offering price per common unit(1)

    $                

Pro forma net tangible book value per unit before the offering(2)

  $                  

Decrease in net tangible book value per unit attributable to purchasers in the offering

   
 

 

 

   

Less: Pro forma net tangible book value per unit after the offering(3)

   
   

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in the offering(4)(5)

    $     
   

 

 

 

 

(1) The mid-point of the price range set forth on the cover of this prospectus.
(2) Determined by dividing the number of units (              common units,              subordinated units and              general partner units) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities.
(3) Determined by dividing the number of units to be outstanding after this offering (              common units,              subordinated units and              general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.
(4) If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $         and $        , respectively.
(5) Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

 

    

Units acquired

   

Total consideration

 

(in millions)

  

Number

  

%

   

Amount

    

%

 

General partner and its affiliates(1)(2)(3)

               $                          

Purchasers in this offering

                        
  

 

  

 

 

   

 

 

    

 

 

 

Total

        100   $           100
  

 

  

 

 

   

 

 

    

 

 

 

 

(1) Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own              common units,              subordinated units and              general partner units.
(2) Assumes the underwriters’ option to purchase additional common units from us is not exercised.
(3) The assets contributed by the general partner and its affiliates were recorded at historical cost in accordance with U.S. GAAP. Book value of the consideration provided by the general partner and its affiliates, as of                     , 2013, after giving effect to the application of the net proceeds of the offering, is as follows:

 

    

(in millions)

 

Book value of net assets contributed

   $                

Less: Distribution to EEP from net proceeds of this offering

  

Distribution to EEP from borrowings under our revolving credit facility

  
  

 

 

 

Total Consideration

   $     
  

 

 

 

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, “Forward-Looking Statements” and “Risk Factors” should be read for information regarding statements that do not relate strictly to historical or current facts and regarding certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, please refer to our historical consolidated financial statements and the accompanying notes and the unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus.

General

Rationale for our cash distribution policy

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. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $         per unit, or $         per unit on an annualized basis, 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, 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. 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.

Limitations on cash distributions and our ability to change our cash distribution policy

Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. Our current cash distribution policy is subject to certain restrictions, as well as the considerable discretion of our general partner in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

 

   

Our revolving credit facility will contain covenants and financial tests that we must satisfy. As a result, our cash distribution policy will be subject to restrictions on cash distributions under our revolving credit facility or other debt agreements we may enter into in the future. One such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under our revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility.”

 

   

The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically,

 

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our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

 

   

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read “Our Partnership Agreement—Amendment of Our Partnership Agreement—No Unitholder Approval.” However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, EEP will own our general partner and will own approximately     % of our outstanding common units and subordinated units on a combined basis (or     % if the underwriters’ option to purchase additional common units is exercised in full). Please read “Our Partnership Agreement—Amendment of Our Partnership Agreement.”

 

   

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating and maintenance or general and administrative expenses, principal and interest payments on our debt, state tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash.”

 

   

Our ability to make cash distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

 

   

If and to the extent our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

To the extent that our general partner determines not to distribute the full minimum quarterly distribution on our common units with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid on the common units with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. The subordinated units will not accrue any arrearages. Any shortfall in the payment of the minimum quarterly distribution on the common units with respect to any quarter during the subordination period may decrease the likelihood that our quarterly distribution rate would increase in subsequent quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

 

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Our ability to grow is dependent on our ability to access external expansion capital

Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon cash from operations and external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. Our revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. Please read “Risk Factors—Risks Related to Our Business—Restrictions in new or any future revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and value of our common units.” To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors—Risks Related to Our Business—Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.”

Our Minimum Quarterly Distribution

Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $         per unit for each whole quarter, or $         per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month in which such distributions are made. We will not make distributions to our unitholders for the period that begins on                     , 2013 and ends on the day prior to the closing of this offering. We will make a prorated distribution on our units covering the period from the completion of this offering through                     , 2013 based on the actual length of that period.

The amount of available cash needed to pay the minimum quarterly distribution on all of our common units, subordinated units and general partner units to be outstanding immediately after this offering for one quarter and on an annualized basis (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units) is summarized in the table below:

 

    

No exercise of option to purchase
additional common units

    

Full exercise of option to purchase
additional common units

 
    

  

  

Aggregate minimum
quarterly distributions

    

  

  

Aggregate minimum
quarterly distributions

 
    

Number
of units

  

One
quarter

    

Annualized
(four quarters)

    

Number
of units

  

One
quarter

    

Annualized
(four quarters)

 

Publicly held common units

      $                    $                       $                    $                

Common units held by EEP

                 

Subordinated units held by EEP

                 

General partner units

                 
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

Total

      $         $            $         $     
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

 

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As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its initial 2% general partner interest. Our general partner will also initially hold all of the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 48%, of the cash we distribute in excess of $         per unit per quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.” We cannot guarantee, however, that we will pay distributions on our common units at our minimum quarterly distribution rate or at any other rate in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in the best interests of our partnership. In making such determination, our general partner 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 us. Please read “Conflicts of Interest and Duties.”

The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.

Additionally, our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.” The minimum quarterly distribution is also subject to adjustment if the holder(s) of the incentive distribution rights (initially only our general partner) elect to reset the target distribution levels related to the incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $         per unit for the twelve months ending June 30, 2014. In those sections, we present two tables, consisting of:

 

   

“Unaudited Pro Forma Distributable Cash Flow,” in which we present the amount of distributable cash flow we would have generated on a pro forma basis for the year ended December 31, 2012

 

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and the twelve months ended March 31, 2013, derived from our unaudited pro forma consolidated financial statements that are included in this prospectus, as adjusted to give pro forma effect to this offering and the related formation transactions; and

 

   

“Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2014,” in which we explain our belief that we will be able to generate sufficient distributable cash flow to support the payment of the minimum quarterly distribution on all units and the corresponding distributions on our general partner’s 2% interest for the twelve months ending June 30, 2014.

Unless otherwise specifically noted, the amounts set forth in the following sections reflect the forecasted and pro forma historical revenues attributable to 100% of the assets and operations of Midcoast Operating and are not adjusted to reflect EEP’s 61% non-controlling interest in Midcoast Operating. We own a 39% controlling interest in Midcoast Operating. Following the closing of this offering, we will consolidate the results of operations of Midcoast Operating and then record a non-controlling interest deduction, initially 61%, for EEP’s retained interest in Midcoast Operating.

Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2012 and the Twelve Months Ended March 31, 2013

If we had completed the transactions contemplated in this prospectus on January 1, 2012, our unaudited pro forma distributable cash flow for the year ended December 31, 2012 would have been approximately $86.4 million. For the year ended December 31, 2012, this amount would have been sufficient to support the payment of the minimum quarterly distribution of $         per unit per quarter ($         per unit on an annualized basis) on all of our common and subordinated units and the corresponding distributions on our general partner’s 2.0% interest for such period.

If we had completed the transactions contemplated in this prospectus on January 1, 2012, our unaudited pro forma distributable cash flow for the twelve months ended March 31, 2013 would have been approximately $88.7 million. For the twelve months ended March 31, 2013, this amount would have been sufficient to pay the minimum quarterly distribution on all of our common and subordinated units and the corresponding distributions on our general partner’s 2.0% interest for such period.

Our unaudited pro forma distributable cash flow for the year ended December 31, 2012 and the twelve months ended March 31, 2013 reflects approximately $4.0 million of estimated incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership, such as: SEC reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. Our unaudited pro forma distributable cash flow for the year ended December 31, 2012 and the twelve months ended March 31, 2013 also reflects approximately $2.0 million of estimated annual expenses attributable to our 39% controlling interest in Midcoast Operating under the financial support agreement that Midcoast Operating will enter into with EEP at the closing of this offering. These expenses are not reflected in the historical financial statements of our Predecessor or unaudited pro forma consolidated financial statements included elsewhere in this prospectus.

We based the pro forma adjustments upon currently available information and the specific estimates and assumptions set forth herein. The pro forma amounts below do not purport to present our results of operations had the transactions described in this prospectus under “Prospectus Summary—The Transactions” actually been completed as of the dates indicated. In addition, distributable cash flow is primarily a cash accounting concept, while our unaudited pro forma consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we been formed in earlier periods.

 

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The following table illustrates, on a pro forma basis, for the year ended December 31, 2012 and the twelve months ended March 31, 2013, the amount of cash that would have been available for distribution to our unitholders and our general partner, assuming in each case that this offering and the other transactions described in this prospectus under “Prospectus Summary—Transactions” had been consummated on January 1, 2012, with respect to each period presented.

Midcoast Energy Partners, L.P.

Unaudited Pro Forma Distributable Cash Flow

 

    

Year ended
December 31,
2012

   

Twelve months
ended
March 31,

2013

 
    (in millions, except per unit
amounts)
 

Pro forma net income attributable to Midcoast Energy Partners, L.P.(1)

  $ 64.1      $ 61.5   

Add:

   

Net income attributable to EEP-retained interest in Midcoast Operating

    117.4        113.5   
 

 

 

   

 

 

 

Pro forma net income

    181.5        175.0   

Add:

   

Depreciation and amortization

    135.0        137.1   

Provision for income taxes

    3.8        3.7   

Interest and other financial costs

    11.0        11.1   

Noncash derivative fair value (gains) losses(2)

    (1.2     2.2   
 

 

 

   

 

 

 

Pro forma Adjusted EBITDA(3)

    330.1        329.1   

Less:

   

Adjusted EBITDA attributable to EEP-retained interest in Midcoast Operating

    201.2        200.8   
 

 

 

   

 

 

 

Pro forma Adjusted EBITDA attributable to Midcoast Energy Partners, L.P.(4)

    128.9        128.3   

Less:

   

Cash interest paid, net(5)

    10.2        10.3   

Income taxes paid(6)

    1.5        1.4   

Maintenance capital expenditures(7)

    24.8        21.9   

Expansion capital expenditures(8)

    234.5        197.8   

Incremental general and administrative costs of being a separate publicly traded partnership(9)

    4.0        4.0   

Financial support agreement(10)

    2.0        2.0   

Add:

   

Contributions from EEP to fund expansion capital expenditures(8)

    234.5        197.8   
 

 

 

   

 

 

 

Pro forma distributable cash flow attributable to Midcoast Energy Partners, L.P.

  $ 86.4      $ 88.7   
 

 

 

   

 

 

 

Pro forma cash distributions:

   

Distributions per unit (based on minimum quarterly distribution rate of $         per unit)

   

Distributions to public common unitholders

   

Distributions to EEP:

   

Common units

   

Subordinated units

   

General partner units

   

Aggregate quarterly distributions

   

Excess (shortfall)

   

Percent of minimum quarterly cash distributions payable to common unitholders

   

Percent of minimum quarterly cash distributions payable to subordinated unitholders

   

 

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(1) Represents pro forma net income attributable to our 39% controlling interest in Midcoast Operating. Reflects a $25.0 million reduction in total annual general and administrative expenses that Midcoast Operating has been allocated historically under existing services agreements with Enbridge and certain of its affiliates. Under our intercorporate services agreement with EEP and certain of its affiliates, EEP has agreed to reduce the total general and administrative expenses that otherwise would have been fully allocable to us by $25.0 million annually following the closing of this offering. Does not reflect approximately $4.0 million of estimated annual incremental general and administrative expenses we expect to incur as a result of being a separate publicly traded partnership or approximately $5.0 million of estimated annual incremental general and administrative expenses we expect Midcoast Operating to incur as a result of Midcoast Operating’s entry into a financial support agreement with EEP.
(2) Noncash derivative fair value gains and losses represent the change in fair value of derivative financial instruments that do not qualify for hedge accounting, which are reflected in net income, but do not affect cash flow until they are settled.
(3) Adjusted EBITDA is defined in “Selected Historical and Pro Forma Financial and Operating Data–Non-GAAP Financial Measures.”
(4) Represents Adjusted EBITDA attributable to our 39% controlling interest in Midcoast Operating.
(5) Represents assumed interest expense and standby fees that we would have paid had our revolving credit facility been in place during the periods presented, less capitalized interest related to the construction of our pipelines, plants and related facilities and our joint venture assets. Does not include assumed upfront commitment fees to be incurred in connection with establishing our revolving credit facility. Borrowings under our revolving credit facility reflect $350.0 million incurred to fund a cash distribution to EEP at the closing of this offering.
(6) Represents our 39% interest in income taxes paid by Midcoast Operating for Texas margin tax incurred for the periods presented. The statutory rate for the Texas margin tax is 1% of qualifying gross margin produced in the state of Texas.
(7) Represents maintenance capital expenditures attributable to our 39% controlling interest in Midcoast Operating. For purposes of determining our pro forma distributable cash flow for the year ended December 31, 2012 and the twelve months ended March 31, 2013, we have assumed that Midcoast Operating has paid maintenance capital expenditures from operating cash flow. Based on our 39% controlling interest in Midcoast Operating, our portion of such maintenance capital expenditures would have been $24.8 million for the year ended December 31, 2012 and $21.9 million for the twelve months ended March 31, 2013. Following the closing of this offering, we expect that Midcoast Operating will continue to fund maintenance capital expenditures through operating cash flow, and we and EEP will each bear our respective share of such maintenance capital expenditures based on our respective interests in Midcoast Operating. For a further discussion of maintenance capital expenditures, please read “—Assumptions and Considerations—Capital Expenditures.”
(8) Represents expansion capital expenditures attributable to our 39% controlling interest in Midcoast Operating. For purposes of determining our pro forma distributable cash flow for the year ended December 31, 2012 and the twelve months ended March 31, 2013, we have assumed that EEP made capital contributions of $234.5 million and $197.8 million, respectively, to fund our portion of the total cost of the expansion capital expenditures for such periods. For a further discussion of expansion capital expenditures, please read “—Assumptions and Considerations—General Considerations and Sensitivity Analysis” and “—Assumptions and Considerations—Capital Expenditures.”
(9) Reflects approximately $4.0 million of estimated annual incremental general and administrative expenses we expect to incur as a result of being a separate publicly traded partnership.
(10) Reflects estimated expenses we expect to incur based on our 39% controlling interest in Midcoast Operating as a result of Midcoast Operating’s entry into a financial support agreement with EEP pursuant to which EEP will guarantee Midcoast Operating’s obligations under derivative agreements and natural gas and NGL purchase agreements. The annual costs that Midcoast Operating will incur under this arrangement, which we estimate will initially be approximately $5.0 million on a 100% basis, will be based on the cumulative average annual amount of letters of credit and guarantees that EEP will provide on Midcoast Operating’s behalf.

 

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Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2014

We forecast our estimated distributable cash flow for the twelve months ending June 30, 2014, will be approximately $67.5 million. This amount would exceed by $         million the amount needed to pay the aggregate annualized minimum quarterly distributions of $         million on all of our outstanding common and subordinated units and the corresponding distributions on our general partner’s 2% interest for the twelve months ending June 30, 2014.

We have not historically made public projections as to future operations, earnings or other results. However, management has prepared the forecast of estimated distributable cash flow for the twelve months ending June 30, 2014, and related assumptions set forth below to substantiate our belief that we will have sufficient available cash to pay the minimum quarterly distribution to all our unitholders and the corresponding distributions on our general partner’s 2% interest for the twelve months ending June 30, 2014. Please read below under “—Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast. This forecast is a forward-looking statement and should be read together with our historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient distributable cash flow to pay the minimum quarterly distribution to all unitholders and our general partner for the forecasted period. However, this information is not fact and should not be relied upon as being necessarily indicative of our future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has not examined, compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report included in this prospectus relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated distributable cash flow.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the forecast or to update this forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this prospective financial information.

 

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Midcoast Energy Partners, L.P.

Estimated Distributable Cash Flow

 

($ in millions)   

Twelve months
ending
June 30, 2014

 

Operating revenue

   $ 5,204.2   

Operating Expenses:

  

Cost of natural gas and natural gas liquids

     4,471.2   

Operating and maintenance

     379.2   

General and administrative(1)

     83.2   

Depreciation and amortization

     156.0   
  

 

 

 

Operating income

     114.6   

Interest expense(2)

     12.6   

Equity earnings from unconsolidated joint ventures

     9.4   
  

 

 

 

Income before income tax expense

     111.4   

Income tax expense

     4.0   
  

 

 

 

Net income

     107.4   

Less:

  

Net income attributable to EEP-retained interest(3)

     75.7   

Net income attributable to Midcoast Energy Partners, L.P.

     31.7   

Add:

  

Net income attributable to EEP-retained interest(6)

     75.7   

Depreciation and amortization

     156.0   

Interest expense

     12.6   

Income tax expense

     4.0   

Distribution in excess of income from unconsolidated joint ventures

     4.4   
  

 

 

 

Estimated Adjusted EBITDA(4)

     284.4   

Less:

  

Estimated Adjusted EBITDA attributable to EEP-retained interest in Midcoast Operating(5)

     175.9   

Estimated Adjusted EBITDA attributable to Midcoast Energy Partners, L.P.

     108.5   

Less:

  

Cash interest paid(2)

     11.8   

Income taxes paid

     1.6   

Maintenance capital expenditures(6)

     27.6   

Expansion capital expenditures(7)

     133.9   

Add:

  

Borrowings to fund expansion capital expenditures(7)

     133.9   
  

 

 

 

Estimated distributable cash flow attributable to Midcoast Energy Partners, L.P.

   $ 67.5   
  

 

 

 

Distribution to public common unitholders

  

Distributions to EEP:

  

Common units

  

Subordinated units

  

General partner units

  
  

 

 

 

Aggregate annualized minimum quarterly distributions

  
  

 

 

 

Excess (shortfall) of distributable cash flow over aggregate annualized minimum quarterly distributions

  

 

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(1) Includes, on a consolidated basis, (a) approximately $4.0 million of estimated annual incremental general and administrative expenses we expect to incur as a result of being a separate publicly traded partnership, (b) approximately $5.0 million that we expect Midcoast Operating to incur under the financial support agreement with EEP and (c) as provided in our intercorporate services agreement with EEP, a $25.0 million reduction in total general and administrative expenses that otherwise would have been fully allocable to us using historical allocation methodologies. Net income attributable to Midcoast Energy Partners, L.P. is shown after giving effect to EEP’s 61% share of the $5.0 million in expenses under the financial support agreement and the $25.0 million general and administrative expense reduction. The estimated $4.0 million in incremental general and administrative expenses will be paid by us and not by Midcoast Operating. Under our intercorporate services agreement with EEP, EEP has agreed to reduce the general and administrative expenses that otherwise would have been fully allocable to us by $25.0 million annually following the closing of this offering.
(2) Includes, on a 100% basis, assumed standby fees and interest expense on borrowings under our revolving credit facility, but does not include assumed upfront commitment fees to be incurred in connection with establishing our revolving credit facility. We expect to borrow $350.0 million under our revolving credit facility at the closing of this offering to fund a cash distribution to EEP. During the forecast period, we estimate that we will incur approximately $133.9 million of additional borrowings under our revolving credit facility to fund expansion capital expenditures at Midcoast Operating on a 39% basis. Please read “—Assumptions and Considerations—Capital Expenditures.”
(3) Represents net income attributable to EEP’s 61% non-controlling interest in Midcoast Operating, calculated as follows:

Net income

   $ 107.4   

Add:

  

Interest expense

     12.6   

Incremental general and administrative costs of being a separate publicly traded partnership

     4.0   
  

 

 

 

Net income – Midcoast Operating

     124.0   

Net income attributable to EEP-retained interest (61%)

     75.7   
(4) Adjusted EBITDA is defined in “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”
(5) Represents estimated Adjusted EBITDA attributable to EEP’s 61% non-controlling interest in Midcoast Operating, calculated as follows:

Estimated Adjusted EBITDA

   $ 284.4   

Add:

  

Incremental general and administrative costs of being a separate publicly traded partnership

     4.0   
  

 

 

 

Estimated Adjusted EBITDA—Midcoast Operating

     288.4   

Estimated Adjusted EBITDA attributable to EEP-retained interest (61%)

     175.9   
(6) Represents estimated maintenance capital expenditures attributable to our 39% controlling interest in Midcoast Operating.
(7) Represents estimated expansion capital expenditures attributable to our 39% controlling interest in Midcoast Operating. We intend to fund these expenditures with borrowings under our revolving credit facility. Following the closing of this offering, we and EEP will each have the right to contribute capital to fund our respective shares of Midcoast Operating’s expansion capital expenditures based on our respective interests in Midcoast Operating. For purposes of this forecast, we have assumed that EEP will fund its 61% share of expansion capital expenditures during the forecast period. If EEP elects not to fund any such expansion capital expenditures, we will have the opportunity to fund all or a portion of EEP’s proportionate share of such expansion capital expenditures in exchange for additional interests in Midcoast Operating. For a further discussion of expansion capital expenditures, please read “—Assumptions and Considerations—General Considerations and Sensitivity Analysis” and “—Assumptions and Considerations—Capital Expenditures.”

 

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Assumptions and Considerations

The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2014. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations, and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable, objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the minimum quarterly distribution rate or at all.

General Considerations and Sensitivity Analysis

 

 

Revenue and cost of natural gas and natural gas liquids are net of intercompany transactions.

 

 

The table below sets forth our estimates for average monthly commodity prices for the twelve months ending June 30, 2014 compared to actual monthly average prices for the year ended December 31, 2012 and the twelve months ended March 31, 2013 and the average forward prices, as of June 1, 2013, for the twelve months ending June 30, 2014. The average prices shown are first-day-of-the-month prices for natural gas and crude oil as quoted on the New York Mercantile Exchange, or NYMEX, and first-day-of-the-month prices for NGLs at Mont Belvieu, as quoted by the Oil Price Information Service, or OPIS. The actual prices that we realize for these commodities reflect various adjustments to the applicable NYMEX- and OPIS-based prices due to transportation, quality and regional price differentials, as well as the effect of our commodity price hedging program described below. Our forecasted estimated commodity prices are primarily based on NYMEX and OPIS forward prices for the applicable commodities, as adjusted to take into account third-party market analysis and management’s own judgment.

 

     Actual Monthly Average      Forward
Curve
     Forecasted  
     Year
ended
December  31,
2012
     Twelve
months
ended
March 31,
2013
     Twelve
months
ending
June 30,
2014(1)
     Twelve
months
ending
June 30,
2014
 

Henry Hub natural gas ($/MMBtu)

   $ 2.97       $ 3.12       $ 4.07       $ 4.12   

NGL composite gallon ($/gallon)(2)

   $ 1.07       $ 0.99       $ 0.77       $ 0.79   

WTI crude oil ($/Bbl)

   $ 93.85       $ 91.71       $ 92.21       $ 92.86   

Mont Belvieu-Conway spread ($/gallon)(3)

   $ 0.18       $ 0.13       $ 0.04       $ 0.04   

 

(1) As of June 6, 2013.
(2) Represents an industry-average composite gallon of NGLs.
(3) The Mont Belvieu—Conway spread is the arithmetic average of the ethane-propane mix spread and the propane spread between the Mont Belvieu and Conway market hubs.

 

 

Our estimated revenue, gross margin and Adjusted EBITDA include the effect of our commodity price hedging program under which we have hedged a portion of the commodity price risk related to our expected NGL sales with swaps and puts, primarily on individual NGL components. Our hedging program for the twelve months ending June 30, 2014 covers approximately 61% of our expected owned natural gas, NGL and condensate volumes for that period. Please read “Management’s Discussion and Analysis of Financial

 

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Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.” The table below represents our hedges in place for the twelve months ending June 30, 2014.

 

Current Hedge Positions for the Twelve Months Ending June 30, 2014

 
     Volume    Hedged Cash
Flow(1)
 
                (in thousands)  

Natural gas

     7,150      MMBtu/d    $ 13,569   

NGLs

     6,010      Bbls/d    $ 115,095   

Condensate

     2,579      Bbls/d    $ 83,429   
       

 

 

 

Total

        $ 212,093   
       

 

 

 

 

(1) Calculated using a weighted average hedge price. For more information regarding our hedge positions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

 

 

Throughput volumes on our systems and realized natural gas and NGL prices are the key factors that will influence whether the amount of distributable cash flow we generate for the twelve months ending June 30, 2014 will exceed or fall below the forecasted amount. For example, based on our 39% controlling interest in Midcoast Operating, if all other assumptions are held constant, a 10% increase or decrease in volumes across all of our assets from forecasted levels would result in a $21.6 million increase or decrease, respectively, in our distributable cash flow. A 10% increase or decrease in the price of natural gas from forecasted levels would result in a $0.4 million increase or decrease, respectively, in our distributable cash flow, and a 10% increase or decrease in the price of NGLs from forecasted levels, including the effect of our existing hedges, would result in a $5.3 million increase or decrease, respectively, in our distributable cash flow. A decrease in forecasted distributable cash flow of greater than $         million would result in our generating less than the minimum cash required to pay the minimum quarterly distributions to our unitholders and the corresponding distributions on our general partner’s 2% interest during the forecast period.

 

 

Following the closing of this offering, EEP will have the option to fund its proportionate share of expansion capital expenditures at Midcoast Operating. If EEP elects not to fund any expansion capital expenditures at Midcoast Operating, we will have the opportunity to fund all or a portion of EEP’s proportionate share of such expansion capital expenditures in exchange for additional interests in Midcoast Operating. For purposes of calculating our estimated distributable cash flow for the twelve months ending June 30, 2014, we have assumed that EEP has elected to fund in full its proportionate share of such expansion capital expenditures. As a result, we have forecasted that our interest in Midcoast Operating will remain at 39% during the forecast period. Please read “—Capital Expenditures” and “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Amended and Restated Limited Partnership Agreement of Midcoast Operating.”

Total Revenue

We estimate that we will generate total revenue of $5.2 billion for the twelve months ending June 30, 2014, compared to pro forma total revenue of $5.4 billion and $5.2 billion for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively. Changes in forecasted revenue primarily relate to fluctuations in natural gas, NGL and condensate prices. Please read “—Gathering and Processing Segment Gross Margin” and “—Logistics and Marketing Segment Gross Margin.”

Purchases of Natural Gas, NGLs and Condensate

We purchase natural gas and NGLs at market prices adjusted for transportation, quality and regional price differentials. We estimate that total purchases of natural gas, NGLs and condensate for the twelve months ending June 30, 2014 will be $4.5 billion, compared to pro forma total purchases of $4.6 billion and $4.5 billion for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively. Forecasted increases in NGL volumes and natural gas prices partially offset the lower cost from lower forecasted NGL prices.

 

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Gathering, Processing and Transportation Segment Gross Margin

We estimate that our gathering, processing and transportation business will generate segment gross margin of $627 million for the twelve months ending June 30, 2014, as compared to pro forma segment gross margin of $676 million and $651 million for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively. The decrease in segment gross margin for the twelve months ending June 30, 2014 compared to the year ended December 31, 2012 and the twelve months ended March 31, 2013 is due primarily to lower forecasted realized prices from sales of our owned NGL volumes, partially offset by forecasted increases in fee-based revenue. Please read “—Fee-Based Segment Gross Margins,” “—Commodity-Based Segment Gross Margins.”

Natural Gas, NGL and Condensate Volumes. We estimate that the total volumes of natural gas gathered and transported on our systems will average 2,537,000 MMBtu/d and the total volumes of liquids produced on our systems will average 104,543 Bpd for the twelve months ending June 30, 2014, compared to an average of approximately 2,613,000 MMBtu/d and 97,428 Bpd, respectively, for the year ended December 31, 2012 and an average of approximately 2,606,000 MMBtu/d and 97,723 Bpd, respectively, for the twelve months ended March 31, 2013.

The following table compares forecasted volumes of natural gas gathered and transported and NGLs produced on our systems for the twelve months ending June 30, 2014 to actual volumes for the year ended December 31, 2012 and the twelve months ended March 31, 2013.

 

     Pro Forma      Forecasted  
    

Year ended
December 31, 2012

    

Twelve months
ended
March 31, 2013

    

Twelve months
ending
June 30, 2014

 

Natural Gas (MMBtu/d)(1)

        

Anadarko system

     1,017,000         1,022,000         1,005,000   

East Texas system

     1,266,000         1,249,000         1,197,000   

North Texas system

     330,000         335,000         335,000   
  

 

 

    

 

 

    

 

 

 

Total

     2,613,000         2,606,000         2,537,000   
  

 

 

    

 

 

    

 

 

 

NGLs (Bpd)(1)

     97,428         97,723         104,543   
  

 

 

    

 

 

    

 

 

 

 

(1) Reflects 100% of the volumes handled by the systems owned by Midcoast Operating during the time periods presented. We own a 39% controlling interest in Midcoast Operating.

We estimate that natural gas volumes will decline by approximately 3% during the twelve months ending June 30, 2014, compared to each of the twelve months ended December 31, 2012 and the twelve months ended March 31, 2013, due to a decrease in dry gas drilling activity, which we expect to be partially offset by an increase in rich gas drilling activity. We forecast that volume growth on our Anadarko system resulting from increased drilling activity in the Anadarko basin, including increased drilling activity related to new acreage dedications from existing customers, will be offset by an expected decrease of approximately 90,000 MMBtu/d during the forecast period resulting from the termination of a customer contract effective August 1, 2013. We forecast decreased volumes on our East Texas system due to less drilling in the dry gas Haynesville and Bossier Shale plays, partially offset by increased drilling in the liquids-rich Cotton Valley formation. We have not forecasted any material change in our contract mix for the twelve months ending June 30, 2014.

Our forecasted increase in NGL volumes during the twelve months ending June 30, 2014 is due to the following:

 

   

the removal of certain capacity constraints at our Allison processing plant due to the construction of additional takeaway capacity to third-party NGL transportation pipelines in April 2012;

 

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the commencement of operations of our new Ajax processing plant during the third quarter of 2013;

 

   

the completion of upgrades to our Trinidad and Avinger processing plants in March 2013 and early 2014, respectively, which will increase the recovery of NGLs at those plants by approximately 1,500 Bpd in the aggregate; and

 

   

an overall increase in the average NGL content of the natural gas being processed by our systems, resulting in higher NGL recoveries per Mcf of natural gas. While both the forecast period and pro forma historical periods assume some level of ethane rejection due to the fractionation value of ethane being close to zero or negative, we are forecasting a higher volume of ethane recovery from our processing activities. At our forecasted prices for ethane and natural gas, whether we reject or recover ethane will not have a material impact on our forecasted financial results.

Fee-Based Segment Gross Margin. Our forecasted fee-based segment gross margin for the twelve months ending June 30, 2014 is expected to increase by approximately 9.0% compared to the year ended December 31, 2012 and the twelve months ended March 31, 2013. We estimate that our fee-based segment gross margin will be approximately $278 million for the twelve months ending June 30, 2014, compared to $254 million for the year ended December 31, 2012 and the twelve months ended March 31, 2013. We estimate that fee-based segment gross margin will comprise approximately 44% of our segment gross margin for the twelve months ending June 30, 2014. The increase in fee-based segment gross margin is due to expected increases in fees under our existing contracts due to inflation escalators and expected renewals of existing contracts and new contracts under which we will provide fee-based processing services.

Commodity-Based Segment Gross Margin. Our commodity-based segment gross margin is derived from retaining a portion of the natural gas, NGLs and condensate we process and produce through our percentage-of-proceeds, percentage-of-liquids and keep-whole/wellhead purchase contracts. We estimate that our commodity-based segment gross margin for the twelve months ending June 30, 2014 will be $349 million, compared to $421 million for the year ended December 31, 2012 and $396 million for the twelve months ended March 31, 2013. The decrease in commodity-based segment gross margin is due to lower forecasted prices for NGLs, partially offset by higher forecasted NGL volumes and higher forecasted natural gas and condensate prices. With respect to our ability to sell NGLs at either Conway or Mont Belvieu, our forecast includes commodity-based segment gross margin of approximately $6 million for the twelve months ending June 30, 2014, compared to $53.3 million for the year ended December 31, 2012 and $39.4 million for the twelve months ended March 31, 2013.

Hedging Program. We hedge a significant portion of our commodity price exposure through the use of natural gas, NGL and crude oil swaps and options. Our hedging program substantially reduces variability in our commodity-based segment gross margin due to fluctuations in natural gas and NGL prices. For the twelve months ending June 30, 2014, we have directly hedged approximately 61% of our estimated commodity-based segment gross margin. As a result, approximately 78% of our total estimated segment gross margin is fee-based or directly hedged.

 

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Texas Express NGL system

The Texas Express NGL system is expected to commence service during the third quarter of 2013. Revenue attributable to the Texas Express NGL system is not included in our financial statements because we account for our 35% joint venture interest in the Texas Express NGL system on an equity basis. Based on current firm volume commitments from contracted shippers on the system, we estimate that we will realize equity earnings of approximately $9.4 million and cash distributions of approximately $13.8 million from the Texas Express NGL system for the twelve months ending June 30, 2014.

Logistics and Marketing Segment Gross Margin

We estimate that our logistics and marketing business will generate segment gross margin of $105.8 million for the twelve months ending June 30, 2014, compared to segment gross margin of $101.7 million for the year ended December 31, 2012 and $95.3 million for the twelve months ended March 31, 2013, on a pro forma basis. Our logistics and marketing business has historically entered into long-term transportation agreements to ensure downstream capacity for natural gas purchased from our gathering, processing and transportation assets. Due to changing pipeline flows and production growth, transportation rates decreased significantly beginning in 2010 and transportation commitments were correspondingly reduced. Annual long-term transportation commitments of approximately $7 million expired during 2012 and early 2013 and were replaced with lower cost transportation contracts. We estimate that our segment gross margin from the sale and transportation of NGLs and other commodities will increase during the forecast period due to an increase in forecasted NGL volumes from our gathering, processing and transportation business. In addition, we anticipate an increase in the volumes of natural gas, NGLs and condensate we transport and market for third parties. To increase our third-party and affiliate activities, we anticipate placing additional facilities in service during the forecast period, including the expansion of our TexPan liquids railcar facility, additional condensate stabilization equipment on our systems and expanded trucking and rail services, which we expect will generate approximately $3 million in gross margin in the aggregate over the forecast period. Finally, we anticipate expanding our NGL and liquids trucking activities in the refinery services area, which involves seasonal activities such as gasoline and butane blending.

Operating and Maintenance

We estimate that operating and maintenance expense for the twelve months ending June 30, 2014 will be $379.2 million, compared to $362.3 million for the year ended December 31, 2012 and $359.4 million for the twelve months ended March 31, 2013, on a pro forma basis. Operating and maintenance expense is comprised primarily of direct labor costs, insurance costs, ad valorem and property taxes, repair and maintenance costs, integrity management costs, utilities and contract services. As such costs are primarily fixed, operating and maintenance expense will not vary significantly with increases or decreases in revenue and gross margin. The estimated increase in operating and maintenance expense during the forecast period is due to the expected commencement of operations of our Ajax processing plant during the third quarter of 2013, the installation of new compressor stations on our Anadarko system, increased property taxes and an assumed 2.5% inflation rate on base operating and maintenance expenses.

General and Administrative

We estimate that general and administrative expense for the twelve months ending June 30, 2014 will be $83.2 million, compared to $80.1 million for the year ended December 31, 2012 and $72.1 million for the twelve months ended March 31, 2013, on a pro forma basis. The estimated increase is primarily due to an estimated $4.0 million of incremental general and administrative expense that we expect to incur as a result of being a separate publicly traded partnership, as well as our proportionate share of Midcoast Operating’s annual expenses under its financial support agreement with EEP, which we estimate will initially be approximately $2.0 million, an estimated 3.5% in annual salary increases and an estimated 2.5% cost of inflation for other variable costs. The year ended December 31, 2012 included $7.4 million of unusual legal and audit expenses incurred during the first

 

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quarter of 2012 related to the investigation of accounting irregularities at our trucking and NGL marketing subsidiary. All periods reflect a $25.0 million annual reduction under our intercorporate services agreement in the total general and administrative expenses that otherwise would have been fully allocable to us under historical allocation methodologies. General and administrative expense is comprised primarily of fixed costs and will not vary significantly with increases or decreases in revenue or gross margin.

Depreciation and Amortization

We estimate that depreciation and amortization expense for the twelve months ending June 30, 2014 will be $156.0 million, compared to $135.0 million for the year ended December 31, 2012 and $137.1 million for the twelve months ended March 31, 2013, on a pro forma basis. Estimated depreciation expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization expense is primarily attributable to additional depreciation associated with capital projects that we expect to be placed in service during the forecast period. Depreciation expenses are derived from asset value and useful life, and therefore will not vary with increases or decreases in revenue and gross margin.

Capital Expenditures

We estimate that total capital expenditures for Midcoast Operating on a 100% basis for the twelve months ending June 30, 2014 will be $413.9 million, compared to $664.9 million for the year ended December 31, 2012 and $563.2 million for the twelve months ended March 31, 2013. Our estimate is based on the following assumptions:

 

   

Maintenance Capital Expenditures. We estimate that maintenance capital expenditures for Midcoast Operating will be approximately $70.7 million on a 100% basis for the twelve months ending June 30, 2014. These expenditures include planned maintenance on its systems and a portion of total well connect capital. This compares to maintenance capital expenditures of $63.6 million and $56.1 million for the year ended December 31, 2012 and the twelve months ended March 31, 2013, respectively. We estimate that the amount of maintenance capital expenditures attributable to our 39% controlling interest in Midcoast Operating will be approximately $27.6 million for the twelve months ending June 30, 2014, compared to $24.8 million for the year ended December 31, 2012 and $21.9 million for the twelve months ended March 31, 2013. Following the closing of this offering, we expect that all of Midcoast Operating’s maintenance capital expenditures will be funded through operating cash flows.

 

   

Expansion Capital Expenditures. We estimate that expansion capital expenditures for Midcoast Operating will be approximately $343.3 million for the twelve months ending June 30, 2014, as compared to $601.4 million for the year ended December 31, 2012 and $507.1 million for the twelve months ended March 31, 2013. These forecasted expansion capital expenditures are comprised of the following:

 

   

approximately $75 million of construction costs associated with the construction of our new Beckville cryogenic processing plant in East Texas, which has a planned capacity of 150 MMcf/d and is intended to service growing rich gas volumes from the Cotton Valley formation in the East Texas basin;

 

   

approximately $250 million for the construction of numerous compressor station projects, pipeline laterals, NGL laterals and well connects on our Anadarko, East Texas and North Texas systems in order to increase volumes of natural gas and NGLs handled by our systems; and

 

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approximately $20 million of construction costs associated with the completion of the Texas Express NGL system during the third quarter of 2013.

We estimate that the amount of expansion capital expenditures attributable to our 39% controlling interest in Midcoast Operating will be approximately $133.9 million for the twelve months ending June 30, 2014, compared to $234.5 million for the year ended December 31, 2012 and $197.8 million for the twelve months ended March 31, 2013. Following the closing of this offering, we expect that we will fund our 39% share of Midcoast Operating’s expansion capital expenditures through borrowings under our revolving credit facility and that EEP will fund its 61% share of Midcoast Operating’s expansion capital expenditures through capital contributions.

Financing

We estimate that interest expense will be approximately $12.6 million for the twelve months ending June 30, 2014, compared to approximately $11.0 million for the year ended December 31, 2012 and $11.1 million for the twelve months ended March 31, 2013. Our estimate of interest expense for the forecast period is based on the following assumptions:

 

   

we will have debt outstanding as of the closing of this offering of $350.0 million;

 

   

our interest expense will include standby fees for the unused portion of our revolving credit facility, as well as upfront commitment fees that will be amortized over the life of our revolving credit facility;

 

   

we will have average outstanding borrowings of $423.0 million under our revolving credit facility, including approximately $133.9 million of borrowings to fund our share of Midcoast Operating’s estimated expansion capital expenditures; and

 

   

we will maintain a low cash balance and therefore not have any interest income.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending June 30, 2014 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

there will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business; and

 

   

there will not be any major adverse change in the midstream energy sector, commodity prices, capital or insurance markets or general economic conditions.

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                     , 2013, we distribute all of our available cash to unitholders of record on the applicable record date. We will make a prorated distribution on our units covering the period from the completion of this offering through                     , 2013 based on the actual length of the period.

Definition of available cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

 

   

less, the amount of cash reserves established by our general partner to:

 

   

provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions, anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC and other administrative proceedings under applicable law subsequent to that quarter);

 

   

comply with applicable law, any of our debt instruments or other agreements; or

 

   

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

 

   

plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Intent to distribute the minimum quarterly distribution

Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that

 

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we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility” for a discussion of the restrictions included in our revolving credit facility that may restrict our ability to make distributions.

General partner interest and incentive distribution rights

Initially, our general partner will be entitled to 2% of all quarterly distributions that we make prior to our liquidation. This general partner interest will be represented by              general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units in this offering, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights).

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48%, of the available cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter. The maximum distribution of 48% does not include any distributions that our general partner or its affiliates may receive on common, subordinated or general partner units that they own. Please read “—General Partner Interest and Incentive Distribution Rights” for additional information.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating surplus

We define operating surplus as:

 

   

$         million (as described below); plus

 

   

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that (1) cash receipts from the termination of a commodity hedge contract or the termination of an interest rate hedge contract not related to the financing of an expansion capital expenditure, in each case prior to its specified termination date, shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such hedge contract and (2) cash receipts from the termination of an interest rate hedge contract related to the financing of an expansion capital expenditure shall not be included in operating surplus; plus

 

   

working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

 

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cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

 

   

cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to pay interest and related fees on debt incurred, or to pay distributions on equity issued, to finance the expansion capital expenditures referred to in the immediately preceding bullet; less

 

   

all of our operating expenditures (as defined below) after the closing of this offering; less

 

   

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

   

all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (1) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (2) sales of equity securities, (3) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements and (4) capital contributions received.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under commodity hedge contracts and interest rate hedge contracts (provided that (1) payments made in connection with the termination of any commodity hedge contract or the termination of any interest rate hedge contract not related to the financing of an expansion capital expenditure, in each case prior to the expiration of its settlement or termination date specified therein, will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such contract and (2) amounts paid in connection with the initial purchase of a commodity hedge contract or the initial purchase of an interest rate hedge contract not related to the financing of

 

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an expansion capital expenditure will be amortized at the life of such contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

 

   

repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

 

   

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

 

   

expansion capital expenditures;

 

   

payment of transaction expenses (including taxes) relating to interim capital transactions;

 

   

payments made in connection with the initial purchase or termination of, or in the ordinary course under, an interest rate hedge contract related to the financing of an expansion capital expenditure;

 

   

distributions to our partners;

 

   

repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or

 

   

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Capital surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 

   

borrowings other than working capital borrowings;

 

   

sales of our equity and debt securities;

 

   

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and

 

   

capital contributions received.

Characterization of cash distributions

All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $         million cash basket, that represent non-operating sources of cash. Consequently, it is possible that all or a portion of specific distributions from operating surplus may represent a return of capital. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.

 

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Capital Expenditures

Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain our asset base, operating capacity or operating income over the long term, or to maintain the existing useful life of any of our capital assets. Examples of maintenance capital expenditures include expenditures to repair, refurbish or replace pipelines or processing facilities, to maintain equipment reliability, integrity and safety or to comply with existing governmental regulations and industry standards.

Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our asset base, operating capacity or operating income over the long term or meaningfully extend the useful life of any of our capital assets. Examples of expansion capital expenditures include the acquisition of additional assets or businesses, as well as capital projects that improve the service 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. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of.

Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

Subordinated Units and Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $         per 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 common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Subordination period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after                     , 2016 that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $         (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

 

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the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $         (the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early termination of the subordination period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending                     , 2014, that each of the following tests are met:

 

   

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $         (150% of the annualized minimum quarterly distribution), plus the related distributions on the incentive distribution rights, for the four-quarter period immediately preceding that date;

 

   

the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (1) $         (150% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis and (2) the corresponding distributions on the incentive distribution rights; and

 

   

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration upon removal of the general partner

In addition, if the unitholders remove our general partner other than for cause during the subordination period:

 

   

the subordinated units held by any person will immediately and automatically convert into a new class of common units on a one-for-one basis, provided that neither such person nor any of its affiliates voted any of its units in favor of the removal;

 

   

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

 

   

our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Expiration of the subordination period

When the subordination period ends, the outstanding subordinated units will convert into a new class of common units, and all common units will no longer be entitled to arrearages. The new class of common units will be convertible at the option of the holder into the class of common units held by the public at any time that the general partner determines, based on the advice of counsel, that the common units to be converted have like economic and federal income tax characteristics to the class of common units held by the public.

Adjusted operating surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

 

   

operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet under the caption “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

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any net increase in working capital borrowings with respect to that period; less

 

   

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

   

any net decrease in working capital borrowings with respect to that period; plus

 

   

any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus

 

   

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash From Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

   

first, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

   

second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

   

third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash From Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

 

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General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled from such 2% interest, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units in this offering, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash. Our general partner may instead fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

The following discussion assumes that our general partner maintains its 2% general partner interest, and that our general partner continues to own the incentive distribution rights.

If for any quarter:

 

   

we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

   

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

 

   

second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

 

   

third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $         per unit for that quarter (the “third target distribution”); and

 

   

thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

 

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Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total quarterly distribution per unit target amount.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

 

    

Total quarterly distribution
per unit target amount

    

Marginal percentage

interest in distributions

 
     

Unitholders

   

General Partner

 

Minimum Quarterly Distribution

   $                                      

First Target Distribution

   above $                    up to $                                   

Second Target Distribution

   above $         up to $                        

Third Target Distribution

   above $         up to $                        

Thereafter

   above $                           

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distributions for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that the holder of the incentive distribution rights will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value

 

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of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period. In addition, our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner (or the then-holder of the incentive distribution rights, if other than our general partner) would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for the quarter;

 

   

second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;

 

   

third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and

 

   

thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (1) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (2) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $        .

 

   

Quarterly distribution

per unit prior to reset

   

Marginal percentage
interest in distributions

   

Quarterly distribution per unit
following hypothetical reset

 
     

Common
unitholders

   

General
partner
interest

   

Incentive
distribution
rights

   

Minimum Quarterly Distribution

  $                            2     —       $              

First Target Distribution

  above $               up to $                          2     —       above $               up to $          (1) 

Second Target Distribution

  above $        up to $                   2     13   above $   (1)    up to $    (2) 

Third Target Distribution

  above $        up to $                   2     23   above $   (2)    up to $    (3) 

Thereafter

  above $                     2     48   above $   (3)   

 

(1) This amount is 115% of the hypothetical reset minimum quarterly distribution.
(2) This amount is 125% of the hypothetical reset minimum quarterly distribution.
(3) This amount is 150% of the hypothetical reset minimum quarterly distribution.

 

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be              common units outstanding, our general partner’s 2% interest has been maintained, our general partner does not own any common units prior to the reset and the average distribution to each common unit would be $         per quarter for the two consecutive non-overlapping quarters prior to the reset.

 

   

Quarterly distribution

per unit prior to reset

   

Cash
distributions
to common
unitholders
prior to
reset

   

Cash distributions to general

partner prior to reset

   

Total
distributions

 
       

Common
units

   

2%
General
partner
interest

   

Incentive
distribution
rights

   

Total

   

Minimum Quarterly Distribution

  $                 $               $               $               $               $               $            

First Target Distribution

  above $        up to $                        

Second Target Distribution

  above $        up to $                 

Third Target Distribution

  above $        up to $                 

Thereafter

  above $          $        $        $        $        $        $     

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be              common units outstanding, our general partner has maintained its 2% general partner interest, and that the average distribution to each common unit would be $        . The number of common units issued as a result of the reset was calculated by dividing (x)             as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $        .

 

   

Quarterly distribution

per unit after reset

   

Cash
distributions
to common
unitholders
after reset

   

Cash distributions to general

partner after reset

   

Total
distributions

 
     

Common
units

   

2%
General
partner
interest

   

Incentive
distribution
rights

   

Total

   

Minimum Quarterly Distribution

  $                 $               $               $               $               $               $            

First Target Distribution

  above $               up to $                        

Second Target Distribution

  above $        up to $                 

Third Target Distribution

  above $        up to $                 

Thereafter

  above $          $        $        $        $        $        $     

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

 

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Distributions from Capital Surplus

How distributions from capital surplus will be made

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

   

first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

 

   

second, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the outstanding common units; and

 

   

thereafter, as if they were from operating surplus.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Effect of a distribution from capital surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, the effects of distributions of capital surplus may make it easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. Then, after distributing an amount of capital surplus for each common unit equal to any unpaid arrearages of the minimum quarterly distributions on outstanding common units, we will make all future distributions from operating surplus, with 50% being paid to the unitholders, pro rata, and 2% to our general partner and 48% to the holders of our incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

 

   

the minimum quarterly distribution;

 

   

the target distribution levels;

 

   

the unrecovered initial unit price;

 

   

the number of general partner units comprising the general partner interest; and

 

   

the arrearages per common unit in payment of the minimum quarterly distribution on the common units.

 

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For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit and general partner unit would be split into two units. We will not make any adjustment by reason of the issuance of additional units for cash or property (including additional common units issued under any compensation or benefit plans).

In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our general partner in accordance with their capital account balances as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of our common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of our subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of adjustments for gain

The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

 

   

first, to our general partner to the extent of any negative balance in its capital account;

 

   

second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of:

(1) the unrecovered initial unit price;

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

(3) any unpaid arrearages in payment of the minimum quarterly distribution;

 

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third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until the capital account for each subordinated unit is equal to the sum of:

(1) the unrecovered initial unit price; and

(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

   

fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;

 

   

fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;

 

   

sixth, 75% to all unitholders, pro rata, and 25% to our general partner, until we allocate under this paragraph an amount per unit equal to:

(1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

(2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence; and

 

   

thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

The percentages set forth above are based on the assumption that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

 

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Manner of adjustments for losses

If our liquidation occurs before the end of the subordination period, after making allocations of loss to the general partner and the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our general partner and unitholders in the following manner:

 

   

first, 98% to the holders of our subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

   

second, 98% to the holders of our common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

   

thereafter, 100% to our general partner.

The percentages set forth above are based on the assumption that our general partner maintains its 2% general partner interest and has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to capital accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. In contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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SELECTED HISTORICAL AND PRO FORMA CONSOLIDATED FINANCIAL

AND OPERATING DATA

The following table shows selected historical consolidated financial and operating data of Midcoast Operating, L.P., our predecessor for accounting purposes, or our Predecessor, and selected pro forma consolidated financial data of Midcoast Energy Partners, L.P. for the periods and as of the dates indicated. The following selected historical consolidated financial and operating data of our Predecessor consists of all of the assets and operations of Midcoast Operating on a 100% basis. In connection with the closing of this offering, EEP will contribute to us a 39% controlling interest in Midcoast Operating. However, as required by U.S. GAAP, we will continue to consolidate 100% of the assets and operations of Midcoast Operating in our financial statements.

The selected historical consolidated financial data of our Predecessor as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010 are derived from the audited consolidated financial statements of our Predecessor appearing elsewhere in this prospectus. The selected historical consolidated financial data of our Predecessor as of December 31, 2010, 2009 and 2008 and for the years ended December 31, 2009 and 2008 are derived from unaudited historical consolidated financial statements of our Predecessor not included this prospectus. The selected historical interim consolidated financial data of our Predecessor as of March 31, 2013 and for the three months ended March 31, 2013 and 2012 are derived from the unaudited interim consolidated financial statements of our Predecessor appearing elsewhere in this prospectus. The following tables should be read together with, and are qualified in their entirety by reference to, the historical and unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The selected pro forma consolidated financial data presented in the following table for the year ended December 31, 2012 and as of and for the three months ended March 31, 2013 are derived from the unaudited pro forma consolidated financial statements included elsewhere in this prospectus. The unaudited pro forma consolidated statement of financial position assumes the offering and the related transactions occurred as of March 31, 2013, and the unaudited pro forma consolidated statements of operations for the year ended December 31, 2012 and the three months ended March 31, 2013 assumes the offering and the related transactions occurred as of January 1, 2012.

The unaudited pro forma consolidated financial statements give effect to the following:

 

   

EEP’s contribution to us of a 38.999% limited partner interest in Midcoast Operating and a 100% member interest in Midcoast OLP GP, L.L.C., which owns a 0.001% general partner interest in Midcoast Operating;

 

   

our issuance of              common units and              subordinated units, representing an aggregate         % limited partner interest in us, to EEP;

 

   

our issuance of              general partner units, representing a 2% general partner interest in us, and all of our incentive distribution rights to our general partner;

 

   

our issuance of              common units, representing a             % limited partner interest in us, to the public in connection with this offering, and our receipt of $         in net proceeds from this offering;

 

   

our entry into a new $             million revolving credit facility and the borrowing of $350.0 million thereunder;

 

   

the application of the proceeds of this offering, together with the proceeds from the borrowings under our revolving credit facility, as described in “Use of Proceeds”; and

 

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our entry into an intercorporate services agreement with EEP and its affiliates, which includes a $25.0 million annual reduction in the total general and administrative expenses that otherwise would have been fully allocable to us by EEP and its affiliates.

The unaudited pro forma consolidated financial statements do not give effect to an estimated $4.0 million of incremental general and administrative expenses that we expect to incur annually as a result of being a separate publicly traded partnership. In addition, the unaudited pro forma consolidated financial statements do not give effect to Midcoast Operating’s entry into a financial support agreement with EEP under which, during the term of the agreement, EEP will guarantee Midcoast Operating’s obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating is a party. Under the financial support agreement, EEP’s guarantee of Midcoast Operating’s obligations will terminate as of the earlier to occur of (1) the fourth anniversary of the closing of this offering and (2) the date on which EEP no longer owns at least a 20% interest in Midcoast Operating. The annual costs Midcoast Operating will incur under the financial support agreement, which we estimate will initially be approximately $5.0 million, will be based on the cumulative average annual amount of letters of credit and guarantees that EEP will provide on Midcoast Operating’s behalf. Based on our 39% controlling interest in Midcoast Operating, we estimate that our proportionate share of these annual expenses will initially be approximately $2.0 million.

 

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The following table presents the non-GAAP financial measure of Adjusted EBITDA, which we use in evaluating the performance of our business. For a definition of Adjusted EBITDA and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with U.S. GAAP, please read “—Non-GAAP Financial Measures.”

 

    Midcoast Operating, L.P. Predecessor Historical     Midcoast Energy
Partners, L.P.
Pro Forma
 
    Year ended December 31,     Three months
ended March 31,
    Year ended
December 31,
    Three
months
ended
March 31,
 
    2012     2011     2010     2009     2008     2013     2012     2012     2013  
    (in millions, except per unit data)  

Income Statement Data(1):

                 

Operating revenues

  $ 5,357.9      $ 7,828.2      $ 6,654.3      $ 4,563.4      $ 8,923.1      $ 1,370.3      $ 1,495.9      $ 5,357.9      $ 1,370.3   

Operating expenses(5)

    5,186.5        7,608.9        6,497.3        4,407.5        8,695.9        1,339.2        1,458.0        5,161.5        1,332.9   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    171.4        219.3        157.0        155.9        227.2        31.1        37.9        196.4        37.4   

Interest expense

    —          —          —          —          —          —          —          11.0        2.8   

Other income (expense)

    (0.1     2.8        3.0        1.0        0.3        0.1