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.

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

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

i

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

ii

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

iii

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

iv

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

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.

1

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.

2

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.

3

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.

4

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.

5

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.

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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			(0.1	)		(0.1	)		0.1
Income (loss) from discontinued operations		—			—			—			(64.9	)		8.3			—			—			—			—
Income tax expense		3.8			2.9			2.6			4.0			3.4			0.5			0.6			3.8			0.5
Net income	$	167.5		$	219.2		$	157.4		$	88.0		$	232.4		$	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		$	2,664.5		$	2,865.1		$	3,991.1								$	3,991.1
Total assets		5,667.4			5,134.6			4,802.6			3,522.6			3,930.3			5,613.9									5,617.7
Long-term debt(2)		—			—			—			—			—			—									350.0
Cash Flow Data(1):
Cash flows provided by operating activities	$	352.7		$	415.6		$	172.4		$	383.1		$	344.8		$	109.3		$	142.3
Cash flows used in investing activities		(614.5	)		(480.1	)		(984.1	)		(13.9	)		(378.1	)		(111.8	)		(141.1	)
Cash flows provided by financing activities		261.8			64.5			811.7			(369.2	)		33.3			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	)		(144.3	)		(327.7	)		(108.6	)		(144.3	)
Other Financial Data:
Adjusted EBITDA(3)	$	305.1		$	348.3		$	294.8		$	312.7		$	284.9		$	67.9		$	69.0		$	330.1		$	74.2
Adjusted EBITDA attributable to Midcoast Energy Partners, L.P.(4)																						$	128.9		$	29.0

footnotes on following page

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

Date of Acquisition / Disposition	Description of Acquisition / Disposition
September 2010	Acquisition of the Elk City system in Oklahoma and Texas.
November 2009	Disposition of natural gas pipelines located predominately outside of Texas.
January 2009	Disposition of an offshore natural gas pipeline.

(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 “—Non-GAAP Financial Measures” below.

(4) Represents Adjusted EBITDA attributable to our 39% controlling interest in Midcoast Operating.

(5) For the year ended December 31, 2008, operating expenses include $20.2 million of charges that relate to an impairment of goodwill associated with our logistics and marketing business.

	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
Operating Statistics:
Throughput (MMBtu/d)
Anadarko		1,017,000		1,013,000		711,000		570,000		647,000		964,000		942,000		1,017,000		964,000
East Texas		1,266,000		1,378,000		1,259,000		1,443,000		1,479,000		1,252,000		1,319,000		1,266,000		1,252,000
North Texas		330,000		337,000		356,000		387,000		395,000		332,000		315,000		330,000		332,000
Total		2,613,000		2,728,000		2,326,000		2,400,000		2,521,000		2,548,000		2,576,000		2,613,000		2,548,000
NGL Production (Bpd)		97,428		87,376		73,647		70,149		68,152		88,498		87,411		97,428		88,498

Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measures of Adjusted EBITDA and gross margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with U.S. GAAP.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before income (loss) from discontinued operations, income taxes, net interest expense, depreciation and amortization, as adjusted for the non-cash, mark-to-market net gains and net losses resulting from changes in the fair value of derivative contracts. Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly traded partnerships in our industry, without regard to financing methods, historical cost basis or capital structure;

• the ability of our assets to generate sufficient cash to support our decision to make distributions to our unitholders;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

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We believe that the presentation of Adjusted EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The U.S. GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and these measures may vary among other companies. As a result, Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities, the most directly comparable U.S. GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.

	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)
Reconciliation of Adjusted EBITDA to net income and cash provided by operating activities:
Net income	$	167.5		$	219.2		$	157.4		$	88.0		$	232.4		$	30.7		$	37.2		$	181.5		$	34.2
Add (deduct):
Depreciation and amortization(1)		135.0			142.7			132.5			140.1			126.2			35.2			33.1			135.0			35.2
Interest expense		—			—			—			—			—			—			—			11.0			2.8
Income tax expense		3.8			2.9			2.6			4.0			3.4			0.5			0.6			3.8			0.5
Income (loss) from discontinued operations		—			—			—			64.9			(8.3	)		—			—			—			—
Derivative fair value net losses (gains)		(1.2	)		(16.5	)		2.3			15.7			(68.8	)		1.5			(1.9	)		(1.2	)		1.5
Adjusted EBITDA		305.1			348.3			294.8			312.7			284.9			67.9			69.0			330.1			74.2
Less: Adjusted EBITDA attributable to EEP ownership in Midcoast Operating																							201.2			45.2
Adjusted EBITDA attributable to Midcoast Energy Partners, L.P.																						$	128.9		$	29.0
Add (deduct):
Interest expense		—			—			—			—			—			—			—
Income tax expense		(3.8	)		(2.9	)		(2.6	)		(4.0	)		(3.4	)		(0.5	)		(0.6	)
Income (loss) from discontinued operations		—			—			—			(64.9	)		8.3			—			—
Other adjustments to reconcile net income to cash provided by operating activities(1)(2)		13.4			12.6			16.9			68.9			40.5			(1.4	)		3.0
Changes in operating assets and liabilities net of acquisitions(3)		38.0			57.6			(136.7	)		70.4			14.5			43.3			70.9
Cash provided by operating activities	$	352.7		$	415.6		$	172.4		$	383.1		$	344.8		$	109.3		$	142.3

(1) As disclosed in our consolidated statements of cash flow.

(2) 2009 includes $64.5 million of loss from the sale of non-core natural gas pipeline assets.

(3) Summation of “Changes in operating assets and liabilities, net of acquisitions” as disclosed in our consolidated statements of cash flow.

Gross Margin

We define gross margin as the sum of segment gross margin in our gathering, processing and transportation business and segment gross margin in our logistics and marketing business. We define segment gross margin in our gathering, processing and transportation business as revenue generated from gathering, processing and transportation operations less the cost of natural gas and natural gas liquids purchased. We define segment gross margin in our logistics and marketing business as revenue generated from the sale of natural gas, NGLs and condensate less the cost of natural gas and natural gas liquids purchased. Gross margin is included as

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a supplemental disclosure because it is one of the primary performance measures used by our management as it represents the results of service fee revenue and cost of sales, which are key components of our operations. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with U.S. GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

For a reconciliation of gross margin to net income, its most directly comparable financial measure calculated and presented in accordance with U.S. GAAP, please read Note 12 to our audited historical consolidated financial statements and Note 7 to our unaudited historical consolidated interim financial statements included elsewhere in this prospectus.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of the financial condition and results of operations for Midcoast Energy Partners, L.P. in conjunction with the historical consolidated financial statements and notes of Midcoast Operating, L.P., our predecessor for accounting purposes (“Midcoast Operating” or our “Predecessor”), and the unaudited pro forma consolidated financial statements of Midcoast Energy Partners, L.P. included elsewhere in this prospectus. Among other things, those historical and unaudited pro forma consolidated financial statements include more detailed information regarding the basis of presentation for the following discussion. Unless the context otherwise requires, references in this section to “we,” “our,” “us,” or like terms, when used in a historical context, refer to our Predecessor and, when used in the present tense or future tense, these terms refer to Midcoast Energy Partners, 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.

This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled “Risk Factors” in this prospectus.

Overview

We are a growth-oriented Delaware limited partnership recently formed by 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. 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.

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

We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

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

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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 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.

• 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 hydrocarbon dewpoint control facilities, or HCDP plants, 10 active natural gas treating plants, one standby natural gas treating plant and one fractionation facility located in the East Texas basin.

• 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.

• 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.

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.

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;

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• 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.

How We Generate Revenue and Segment Gross Margin

Gathering, Processing and Transportation

Revenues for our gathering, processing and transportation business are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported and sold through our systems; the volumes of NGLs sold; and the level of natural gas, NGL and condensate prices. The segment gross margin of our gathering, processing and transportation business is derived from the compensation we receive from customers in the form of fees or commodities we receive for providing our services, coupled with the proceeds we receive for the sales of natural gas, NGLs and condensate to affiliates and third-parties.

We generate revenues and segment gross margin principally under the following types of contractual arrangements:

Fee-Based Arrangements. In a fee-based arrangement, we receive a fee per Mcf of natural gas processed or per gallon of NGLs produced. Under this arrangement, we have no direct commodity price exposure. Revenues of our gathering, processing and transportation business that are derived from transmission services consist of reservation fees charged for transportation of natural gas on some of our intrastate pipeline systems. Customers paying these fees typically pay a reservation fee each month to reserve capacity plus a nominal commodity charge based on actual transportation volumes. Reservation fees are required to be paid whether or not the shipper delivers the volumes, thus referred to as a ship-or-pay arrangement. Additional revenues from our intrastate pipelines are derived from the combined sales of natural gas and transportation services.

Commodity-Based Arrangements. Our gathering, processing and transportation business also generates revenue and segment gross margin under other types of service arrangements with customers. These arrangements expose us to commodity price risk, which we mitigate to a substantial degree with the use of derivative financial instruments. Please read “—Quantitative and Qualitative Disclosures about Market Risk” for more information about the derivative activities we use to mitigate our exposure to commodity price risk.

The commodity-based service contracts we have with customers are categorized as follows:

• Percentage-of-Proceeds. In a percentage-of-proceeds arrangement, we receive a negotiated percentage of the natural gas and NGLs we process in the form of residue natural gas, NGLs, condensate and sulfur, which we can sell at market prices and retain the proceeds as our compensation. This type of arrangement exposes us to commodity price risk, as the revenues from percentage-of-proceeds contracts directly correlate with the market prices of the applicable commodities that we receive.

• Percentage-of-Liquids. In a percentage-of liquids arrangement, we receive a negotiated percentage of the NGLs extracted from natural gas that require processing, which we can then sell at market prices and retain the proceeds as our compensation. This contract structure is similar to percentage-of-proceeds arrangements except that we only receive a percentage of the NGLs produced. This type of contract may also require us to provide the customer with a guaranteed NGL recovery

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percentage regardless of actual NGL production. Since revenues from percentage-of-liquids contracts directly correlate with the market price of NGLs, this type of arrangement also exposes us to commodity price risk.

• Percentage-of-Index. In a percentage-of index arrangement, we purchase raw natural gas at a negotiated percentage of an agreed upon index price. We then resell the natural gas, generally for the index price, and keep the difference as our compensation.

• Keep-Whole/Wellhead Purchase. In a keep-whole/wellhead purchase arrangement, we gather or purchase raw natural gas from the customer. We extract and retain the NGLs produced during processing for our own account, which we then sell at market prices. In instances where we purchase raw natural gas at the wellhead, we may also sell the resulting residue natural gas for our own account at market prices. In those instances when we gather and process raw natural gas for the customer’s account, we generally must return to the customer residue natural gas with an energy content equivalent to the original raw natural gas we received, as measured in British thermal units, or Btu. This type of arrangement has the highest commodity price exposure because our costs are dependent on the price of natural gas purchased and our revenues are dependent on the price of NGLs sold. As a result, we benefit from these types of contracts when the value of the NGLs is high relative to the cost of the natural gas and are disadvantaged when the cost of the natural gas is high relative to the value of the NGLs.

Under the terms of each of our commodity-based service contracts, we retain natural gas and NGLs as our compensation for providing these customers with our services. We seek to hedge our commodity price exposure resulting from such compensation by implementing a hedging strategy that targets, as of any particular date, hedging approximately 70% of our commodity price exposure during the first twelve-month period immediately following that date and approximately 50% of our commodity price exposure during the next succeeding twelve-month period. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell the residue gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate. Many of the derivative financial instruments we use do not qualify for hedge accounting. As a result we record the changes in fair value of the derivative instruments that do not qualify for hedge accounting in our operating results. This accounting treatment produces unrealized non-cash, mark-to-market gains and losses in our reported operating results that can be significant during periods when the commodity price environment is volatile.

Logistics and Marketing

Our logistics and marketing business derives a majority of its segment gross margin from purchasing and receiving natural gas, NGLs and other products from our gathering, processing and transportation business and from third-party pipeline systems and processing plants and selling and delivering them to wholesale customers, such as distributors, refiners, fractionators, utilities, chemical facilities and power plants. We contract for third-party pipeline capacity under firm and interruptible transportation contracts for which the pipeline capacity depends on volumes of natural gas from our natural gas assets, which provides us with access to several third-party interstate and intrastate pipelines that can be used to transport natural gas and NGLs to primary market hubs where they can be sold to major customers for these products. Our logistics and marketing business also uses owned and leased trucks and specialized trailers and railcars to transport products such as NGLs, condensate and other liquid hydrocarbons to market. In some instances, our margin per unit of volume sold can be higher if the commodity being marketed requires specialized handling, treating, stabilization or other services.

Our logistics and marketing business also derives segment gross margin from the relative difference in natural gas and NGL prices between the contracted index at which the natural gas and NGLs are purchased and the index price at which they are sold, otherwise known as the “basis spread,” which can vary over time or by location, as well as due to local supply and demand factors. Natural gas and NGLs purchased and sold by our logistics and marketing business is primarily priced at a published daily or monthly price index. Sales to

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wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated margins result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. We enter into long-term, fixed-price purchase or sales contracts with our customers and generally will enter into offsetting hedge positions under the same or similar terms.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements regularly. These metrics include gross margin, segment gross margin, throughput and production volumes, direct operating expenses and Adjusted EBITDA. Gross margin and Adjusted EBITDA are non-GAAP financial measures.

Segment Gross Margin and Gross Margin

Segment gross margin is among the primary metrics that we use to evaluate our performance. We believe that segment gross margin gives a more meaningful indication of the financial performance of our business segments as compared to revenue because segment gross margin takes into account the impact of commodity prices on both revenue and cost of goods sold. We define segment gross margin in our gathering, processing and transportation business as revenue generated from gathering, processing and transportation operations less the cost of natural gas and natural gas liquids purchased. We define segment gross margin in our logistics and marketing business as revenue generated from the sale of natural gas, NGLs and condensate less the cost of natural gas and natural gas liquids purchased. We define gross margin as the sum of the segment gross margin of our gathering, processing and transportation business and the segment gross margin of our logistics and marketing business. For more information regarding gross margin, please read “Selected Historical and Pro Forma Consolidated Financial and Operating Data—Non-GAAP Financial Measures.”

Natural Gas Throughput and NGL Production Volumes

The amount of revenue and segment gross margin we generate primarily depends on the volumes of natural gas we gather at the wellhead, the quantities of NGLs recovered from our processing activities and the volumes of natural gas and NGLs transported on our systems for customers. The volumes of natural gas gathered and NGLs recovered on our systems are largely dependent on the supply of natural gas in the markets served directly by our assets and the demand for natural gas and NGL products. We must continually obtain new supplies of natural gas to maintain or increase the throughput volumes on our systems. Our ability to maintain or increase existing volumes of natural gas and obtain new supplies is impacted by (1) the level of successful drilling activity in areas currently dedicated to or near our gathering systems, (2) our ability to compete for volumes from successful new wells in the areas in which we operate, (3) our ability to obtain natural gas that has been released from other commitments and (4) the volume of natural gas that we purchase from connected systems. We actively monitor producer activity in the areas served by our gathering, processing and transportation systems to pursue new supply opportunities.

Direct Operating Expenses

Our management seeks to maximize the profitability of our operations in part by optimizing direct operating expenses, which are reflected in our historical and unaudited pro forma consolidated financial statements included elsewhere in this prospectus as “operating and maintenance expenses.” Direct labor costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs and utilities comprise the most significant portion of our direct operating expenses. These expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We seek to manage the timing of our routine maintenance expenditures on our pipelines, plants and related facilities to avoid disruption of our operations during critical times and to minimize asset downtime.

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Adjusted EBITDA

We use Adjusted EBITDA to analyze our performance. We define Adjusted EBITDA as net income (loss) before income (loss) from discontinued operations, income taxes, net interest expense, depreciation and amortization, as adjusted for the non-cash, mark-to-market net gains and net losses resulting from changes in the fair value of derivative contracts.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

• our operating performance as compared to other publicly traded partnerships in our industry, without regard to historical cost basis or financing methods;

• the ability of our assets to generate sufficient cash to support our decision to make distributions to our unitholders;

• our ability to incur and service debt and fund capital expenditures; and

• the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA in this prospectus provides useful information to investors in assessing our financial condition and results of operations. The U.S. GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted EBITDA should not be considered as an alternative to net income or net cash provided by operating activities calculated in accordance with U.S. GAAP. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP.

You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under U.S. GAAP. Additionally, because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

For a further discussion of the non-GAAP financial measure of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most comparable measures calculated and presented in accordance with U.S. GAAP, please read “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

Items Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to our Predecessor’s historical results of operations for the reasons described below:

• Our Predecessor’s results of operations historically reflected 100% of the revenues and expenses relating to Midcoast Operating. At the closing of this offering, EEP will contribute to us 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 initially record a 61% non-controlling interest deduction for EEP’s retained interest in Midcoast Operating. Additionally, although EEP will have the option to fund its pro rata share of Midcoast Operating’s expansion capital expenditures, to the extent it elects not to do so, we may elect to fund EEP’s portion in exchange for additional interests in Midcoast Operating and, as a result, our interest in Midcoast Operating would increase over time. Please read “—Future Growth Opportunities—Acquisitions of Additional Interests in Midcoast Operating.”

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• Although the allocation methodology under which we will continue to reimburse EEP and its affiliates for the provisions of certain administrative and operational services to Midcoast Operating will not change, $25.0 million in annual general and administrative expenses that were allocated to Midcoast Operating historically under its existing services agreements will not be allocated to Midcoast Operating following the closing of this offering. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Intercorporate Services Agreement.”

• We expect to incur an additional $4.0 million of incremental annual general and administrative expenses as a result of being a separate publicly traded partnership, 100% of which will be attributable to us.

• Following the closing of this offering, during the term of the financial support agreement Midcoast Operating will enter into with EEP, EEP will provide letters of credit and guarantees in support of Midcoast Operating’s financial obligations under certain legacy hedges and key customer natural gas and NGL purchase agreements. 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. EEP has historically provided such financial support to Midcoast Operating at no cost.

• Following the closing of this offering, we will incur interest expense under our revolving credit facility and other borrowing arrangements we may enter into from time to time. Prior to our acquiring control of our Predecessor, it was a wholly owned subsidiary of EEP and, as such, did not incur any direct interest expense from third parties and only recognized intercompany interest expense to the extent such amounts were capitalized as part of its construction projects.

Factors and Trends that Impact Our Business

We expect our business to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

Natural Gas and NGL Supply and Demand Outlook. Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Fluctuations in natural gas and NGL prices can affect production rates. Generally, drilling and production activity will increase as natural gas and NGL prices increase. The Inside FERC First of Month Henry Hub index prices for natural gas have recently risen after a steady decline over the past several years. As of June 1, 2013, the forward curve for the twelve months ending June 30, 2014 was $4.12 per MMBtu, as compared to an average price of $3.34 for the year ended December 31, 2012. This index price was as high as $13.11 per MMBtu in July 2008. In part as a result of the prevailing prices during the past several years, producer activity levels around some of our systems have declined or been refocused on “rich” gas, or natural gas reserves containing relatively higher levels of crude oil, NGLs and condensate. While natural gas drilling and permitting activity has declined over the past three years, throughput on our systems has remained relatively flat due to low average decline rates on wells that have been producing for extended periods of time, as well as a shift in drilling activity, primarily focused on rich gas formations within our areas of operation. Additionally, because producers have been focusing their drilling efforts on areas with rich gas production, the amount of NGLs that our systems produce has steadily increased, despite the relatively flat natural gas throughput on our systems. We expect that dry natural gas drilling will increase in the basins in which our systems are located when natural gas producers experience sustained natural gas prices of approximately $4.50 per MMBtu or greater.

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Growth in the supply of natural gas has resulted in lower natural gas prices which, in turn, has increased demand for natural gas and contributed to price stabilization and, more recently, an increase in natural gas prices. Demand for natural gas is expected to grow due to increased demand for natural gas-fired electric power generation. This increase is related to expected economic growth, coal-fired plant retirements and the cost advantage of natural gas relative to coal. Over the long term, we expect global demand for natural gas to grow significantly as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Global demand for natural gas is projected by the International Energy Agency to grow by more than 24 Tcf between 2010 and 2020, primarily fueled by the growth of emerging economies. The U.S. Department of Energy has recently approved two natural gas export permits that will allow exports of liquefied natural gas, or LNG, along the U.S. Gulf Coast in close proximity to our assets. According to EIA, LNG exports could increase demand for natural gas by approximately 4.4 Bcf/d by 2027.

Because of the current market prices of crude oil and NGLs, drilling activity in 2013 is expected to remain steady in shale plays containing crude oil, condensate and NGL-rich natural gas production, such as the Granite Wash, Cotton Valley, Barnett Shale, Eagle Ford, Bakken, Niobrara, Mississippian, Wolfcamp, Woodford, Marcellus and Utica Shales. Drilling activity in predominantly dry gas shale plays, such as the Haynesville/Bossier and Fayetteville Shales, is expected to improve when natural gas prices further improve. As a result of producers’ recent success in developing rich gas shale plays, ethane production has increased more rapidly than the ethylene industry’s capability to consume it, which has contributed to a decrease in ethane prices when compared to 2011. We believe this ethane surplus will generally persist until ethylene producers increase their capacity to consume additional ethane feedstock volumes through plant modifications and expansions and the completion of recently announced new ethylene plants that are expected to commence service during the 2016-2018 timeframe. This ethane surplus has resulted in lower ethane prices and periods of ethane rejection in an effort to balance supply and demand.

Commodity Prices. Our profitability is directly impacted by the price of NGLs and, to a lesser extent, natural gas. Our segment gross margin generally increases in an environment of increasing commodity prices, primarily as a result of our gathering, processing and transportation contract portfolio, which performs better in such an environment. The recent commodity price supply and demand dynamics discussed above have resulted in significant downward pressure in current and forward NGL prices. As a result, some of our plants were periodically rejecting ethane and leaving it in the natural gas stream when it was more valuable being sold as natural gas than as a stand-alone commodity.

The direct impact of changes in natural gas prices from our percent-of-proceeds contracts that generate higher margins in higher natural gas price environments is largely offset by our keep-whole/wellhead purchase contracts that generate lower margins in higher natural gas price environments. In addition, we seek to hedge our commodity price exposure by implementing a hedging strategy that targets, as of any particular date, hedging approximately 70% of our commodity price exposure during the first twelve-month period immediately following that date and approximately 50% of our commodity price exposure during the next succeeding twelve-month period. For additional information regarding our hedging activities, please read “—Quantitative and Qualitative Disclosures About Market Risk.”

Growth Associated with Acquisitions and Expansion Projects. We believe we are well-positioned to achieve growth based on the combination of our relationship with EEP and Enbridge and our strategically located assets, which serve areas in the Anadarko, East Texas and North Texas basins that require significant midstream infrastructure. When production increases in our areas of operation, we believe that we will have a competitive advantage in attracting customers to our systems through our existing capacity or relatively low-cost expansions. We may also acquire additional interests in Midcoast Operating from EEP or purchase assets from third parties. We are constructing plants and pipelines with an aggregate projected cost of approximately $755 million, of which $542.5 million is expected to have been expended by June 30, 2013. We expect these projects, when completed, will allow us to grow our cash flows and earnings to capitalize on the activity of third party producers around our systems.

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Future Growth Opportunities

We intend to expand our operations by pursuing the acquisition of additional interests in Midcoast Operating from EEP, as well through organic growth projects 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. Additionally, we intend to pursue complementary third-party acquisitions to expand our business.

Acquisitions of Additional Interests in Midcoast Operating

EEP has indicated that it intends to offer us the opportunity to purchase additional interests in Midcoast Operating from time to time. These acquisitions, sometimes referred to as “drop-down” transactions, will provide an alternative source of funding for EEP while at the same time providing an opportunity for meaningful growth in our cash flows. 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. We believe that we will be well-positioned to acquire additional interests in Midcoast Operating if the opportunity arises.

Under the amended and restated limited partnership agreement of Midcoast Operating that we and EEP will enter into at the closing of this offering, we and EEP will each have the option to contribute our proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund expansion capital expenditures or other growth projects. To the extent that we or EEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions to Midcoast Operating to the extent necessary to fully fund such expenditures in exchange for additional ownership interests in Midcoast Operating. For more information, please read “Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Capital Expenditures” and “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Amended and Restated Limited Partnership Agreement of Midcoast Operating.”

Organic Growth Projects

We are currently pursuing several organic expansion projects that are designed to increase the natural gas processing, NGL production and natural gas and NGL transportation capacity of our gathering, processing and transportation business. The following table sets forth certain projects we are currently undertaking that we expect to place into service during future periods:

Project	Total Estimated Capital Costs			Expected In-service Date
	(in millions)
Texas Express NGL system	$	385	(1)	Third quarter 2013
Ajax cryogenic processing plant	$	230		Third quarter 2013
Beckville cryogenic processing plant	$	140		Early 2015

(1) Midcoast Operating owns a 35% joint venture interest in the Texas Express NGL system. Estimated capital costs represent 35% of the total projected costs associated with constructing both the mainline and the gathering system.

Texas Express NGL System. We own a 35% interest in the Texas Express NGL system, which consists of two separate joint ventures with third parties to design and construct a new NGL pipeline and NGL gathering system. The Texas Express NGL mainline originates near Skellytown, Texas in the Texas Panhandle and, when completed, will extend approximately 580 miles to NGL fractionation and storage facilities in the Mont Belvieu area on the Texas Gulf Coast. The mainline is expected to have an initial capacity of approximately 280,000 Bpd and will be expandable to approximately 400,000 Bpd with the addition of intermediate pump stations on the system. There are currently capacity reservations on the mainline that, when fully phased in, will total approximately 250,000 Bpd. Based on existing capacity reservations, our logistics and marketing business will be a

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significant shipper on the system. The new NGL gathering system will initially consist of approximately 116 miles of gathering lines that will connect the mainline to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma and to Barnett Shale processing plants in North Texas. The gathering system is currently expected to include 270 miles of gathering lines by 2019. The joint venture that will own the mainline portion of the Texas Express NGL system is owned 35% by Enterprise Products Partners, 35% by us, 20% by Anadarko Petroleum Corporation and 10% by DCP Midstream, LLC, or DCP Midstream. The joint venture that will own the new NGL gathering system is owned 45% by Enterprise Products Partners, 35% by us and 20% by Anadarko Petroleum Corporation. Enterprise Products Partners is constructing and will serve as the operator of the mainline, while we are constructing and will operate the new gathering system. The mainline and the initial portion of the gathering system are expected to begin service during the third quarter of 2013. We expect that the Texas Express NGL system 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. As of March 31, 2013, we have made contributions of approximately $216.4 million for the construction of the Texas Express NGL system. We expect to contribute an additional $168.6 million in connection with the Texas Express NGL system.

Ajax Cryogenic Processing Plant. We expect development of the Granite Wash play in the Texas Panhandle and western Oklahoma to continue due to the prolific nature of the wells, current market prices for NGLs and crude oil and the application of horizontal drilling and fracturing technology to the formation. In order to accommodate the expected growth of the Granite Wash play, we are currently constructing a cryogenic processing plant, which we refer to as our Ajax processing plant, and field and plant compression, gathering infrastructure and NGL pipelines on our Anadarko system, all of which we expect to place into service upon completion of the Texas Express NGL system in the third quarter of 2013. We estimate the total cost of the Ajax processing plant and related facilities to be approximately $230 million. When operational, we expect that the Ajax processing plant will increase the total processing capacity of our Anadarko system by approximately 150 MMcf/d to approximately 1,150 MMcf/d and will also increase the system’s condensate stabilization capacity by approximately 2,000 Bpd. We also expect that the Ajax processing plant will be capable of producing approximately 15,000 Bpd of NGLs.

Beckville Cryogenic Processing Plant. In late 2013, we expect to initiate construction of our Beckville cryogenic processing plant on our East Texas system. This plant will serve existing and prospective customers pursuing production in the Cotton Valley formation, which is comprised of approximately ten counties in East Texas and has been a steady producer of natural gas for decades. Production from this play typically contains two to three gallons of NGLs per Mcf. The region currently produces approximately 1.8 Bcf/d of natural gas with 72,000 Bpd of associated NGLs. Until recently, the primary exploitation method in the Cotton Valley formation has been vertical wells. Lower horizontal drilling costs, coupled with the latest fracturing technology, has brought significant interest back to this area. Economics associated with horizontal wells in the Cotton Valley formation compare favorably to other rich natural gas plays, which has encouraged producers to increase drilling activity in the region. We expect our Beckville processing plant to be capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs. We estimate the cost of constructing the plant to be approximately $140 million and expect it to commence service in early 2015.

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Summary of Consolidated Operating Results

The following table reflects our consolidated operating income for the three month periods ended March 31, 2013 and 2012 and for each of the years ended December 31, 2012, 2011 and 2010.

	Three months ended March 31,						Year ended December 31,
	2013			2012			2012			2011			2010
	(in millions)
Operating Income
Gathering, processing and transportation	$	35.2		$	60.0		$	191.5		$	195.3		$	148.5
Logistics and marketing		(4.1	)		(22.1	)		(19.9	)		24.1			8.9
Corporate, operating and administrative		—			—			(0.2	)		(0.1	)		(0.4	)
Total Operating Income		31.1			37.9			171.4			219.3			157.0
Other income (expense)		0.1			(0.1	)		(0.1	)		2.8			3.0
Income tax expense		0.5			0.6			3.8			2.9			2.6
Net income	$	30.7		$	37.2		$	167.5		$	219.2		$	157.4

Results of Operations—By Segment

Gathering, Processing and Transportation

The following table sets forth the operating results of our gathering, processing and transportation business and the approximate average daily volumes of natural gas throughput and NGLs produced on our systems for the periods presented.

	Three months ended March 31,				Year ended December 31,
	2013		2012		2012		2011		2010
	(in millions)
Operating revenues	$	172.2	$	189.9	$	818.0	$	914.2	$	598.5
Cost of natural gas and natural gas liquids		17.4		11.0		131.2		271.1		78.3
Segment Gross Margin		154.8		178.9		686.8		643.1		520.2
Operating and maintenance		64.2		65.5		281.5		241.0		191.4
General and administrative		21.9		22.1		85.8		71.6		52.1
Depreciation and amortization		33.5		31.3		128.0		135.2		128.2
Operating expenses		119.6		118.9		495.3		447.8		371.7
Operating Income	$	35.2	$	60.0	$	191.5	$	195.3	$	148.5
Operating Statistics Throughput (MMBtu/d)
Anadarko(1)		964,000		942,000		1,017,000		1,013,000		711,000
East Texas		1,252,000		1,319,000		1,266,000		1,378,000		1,259,000
North Texas		332,000		315,000		330,000		337,000		356,000
Total		2,548,000		2,576,000		2,613,000		2,728,000		2,326,000
NGL Production (Bpd)		88,498		87,411		97,428		87,376		73,647

(1) Average daily volumes for the years ended December 31, 2012, 2011 and 2010 include 255,000 MMBtu/d, 251,000 MMBtu/d, and 66,000 MMBtu/d, respectively, of volumes associated with the Elk City system we acquired in September 2010.

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Three months ended March 31, 2013 compared with three months ended March 31, 2012

Segment Gross Margin. The segment gross margin of our gathering, processing and transportation business for the three months ended March 31, 2013 decreased approximately $24.1 million from the segment gross margin produced in the same period of 2012, primarily as a result of declines in NGL prices. Prices for NGLs have declined significantly when compared to prices for the same period in 2012. NGLs declined approximately 11% and 27% per composite barrel for the three months ended March 31, 2013 compared to the three months ended March 31, 2012, based upon the prevailing prices at the Conway and Mont Belvieu market hubs, respectively. On our Anadarko system, we purchase some NGLs at Conway hub prices and then have the ability to resell the NGLs at Mont Belvieu hub prices. The decline in NGL prices during the three months ended March 31, 2013 has narrowed the difference in prices between these market hubs from the same period in 2012, which also contributed to the decline in segment gross margin.

Average daily gas volumes on our systems for the three months ended March 31, 2013 decreased slightly by approximately 28,000 MMBtu/d, or 1.1%, compared to the three months ended March 31, 2012, due to reduced drilling around dry gas areas on our East Texas system. NGL production on our systems increased approximately 1,087 Bpd, or 1.2%, for the three months ended March 31, 2013 compared to the three months ended March 31, 2012, due to additional drilling by producers in liquids-rich areas within our systems, particularly the Granite Wash play on our Anadarko system. The increase in NGL production would have been higher if we had produced all of the recoverable ethane within the natural gas stream. Due to low ethane prices on our Anadarko system during the three months ended March 31, 2013, however, it was more profitable to operate our plants in ethane rejection mode, which results in our ability to sell the ethane as part of the natural gas stream.

A major variable in our operating results relates to the commodity-based margin we generate from our natural gas processing activities. Under percentage of liquids contracts, we are required to pay producers a contractually fixed recovery of NGLs regardless of the NGLs we physically produce or our ability to process the NGLs from the natural gas stream. We refer to NGLs that are produced in excess of this contractual obligation, in addition to the barrels that we produce under traditional gas processing arrangements, collectively as “processing gross margin.” Segment gross margin attributable to processing gross margin for the three months ended March 31, 2013 decreased $13.0 million from the three months ended March 31, 2012. The decline in processing gross margin is the result of a decline in NGL production related to this type of contract, partially from the rejection of ethane as discussed above, and lower NGL prices for the three months ended March 31, 2013 when compared to the three months ended March 31, 2012.

Impact of Derivatives on Segment Gross Margin. For the three months ended March 31, 2013, our gathering, processing and transportation business recognized $1.4 million of unrealized non-cash, mark-to-market net gains as compared with $1.4 million of net gains recognized for the same period of 2012.

Operating and Maintenance. The operating and maintenance costs of our gathering, processing and transportation business for the three months ended March 31, 2013 decreased by approximately $1.3 million compared to the three months ended March 31, 2012, primarily due to lower compressor rental costs coupled with reduced repairs and maintenance costs. We implemented cost control measures in late 2012 to minimize operating costs through various programs, such as by purchasing rather than leasing compressors. These measures helped to mitigate inflationary growth in our operating and maintenance costs during the three months ended March 31, 2013.

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General and Administrative. Our general and administrative costs for the three months ended March 31, 2013 were slightly lower than for the three months ended March 31, 2012 due primarily to a reduction in outside contract services needed to support the operations of our gathering, processing and transportation business.

Depreciation and Amortization. Our depreciation and amortization expense for the three months ended March 31, 2013 was approximately $2.2 million higher than for the three months ended March 31, 2012, primarily due to a full three months of depreciation for our Allison processing plant and related facilities during the 2013 period, coupled with other assets that we placed into service after March 31, 2012.

Year ended December 31, 2012 compared with year ended December 31, 2011

Segment Gross Margin. Segment gross margin of our gathering, processing and transportation business for the year ended December 31, 2012 increased by $43.7 million from the year ended December 31, 2011 due to higher NGL production partially offset by lower commodity prices and natural gas volumes, as well as other factors described below. Average natural gas prices declined approximately 31% per MMBtu for the year ended December 31, 2012 compared to the year ended December 31, 2011, based upon the NYMEX Henry Hub pricing index. NGL prices declined approximately 30% and 28% per composite barrel for the year ended December 31, 2012 compared to the year ended December 31, 2011, based upon average pricing at the Conway and Mont Belvieu market hubs, respectively.

We increased the processing capacity of our Anadarko system when we completed our Allison processing plant in November 2011 and obtained additional NGL takeaway capacity in April 2012, which enabled us to effectively process more natural gas and produce more NGLs on the system. Despite the decline in NGL prices, our processing gross margin on this system for the year ended December 31, 2012 increased by $49.2 million over the year ended December 31, 2011. The increase in processing gross margin was attributable to our increased ability to effectively process natural gas and produce NGLs due to the completion of our Allison processing plant.

Average daily natural gas volumes on our systems for the year ended December 31, 2012 decreased approximately 115,000 MMBtu/d, or 4.2%, compared to the year ended December 31, 2011 due to reduced drilling in dry gas areas and declines in recently added wells, primarily on our East Texas system. This volume decrease was partially offset by an increase in volumes due to more favorable winter weather conditions than those that adversely impacted natural gas production in 2011. NGL production during the year ended December 31, 2012 increased approximately 10,052 Bpd, or 11.5%, compared to the year ended December 31, 2011 due to producers focusing their drilling activities on more liquids-rich formations within our operating areas, as well as the completion of our Allison processing plant.

For the year ended December 31, 2012, segment gross margin increased $13.0 million when compared with the year ended December 31, 2011 due to additional fee-based revenue generated by each of our systems. The additional fee-based revenue was primarily attributable to additional compression fees, increased charges for gathering services and additional volumes from the recent expansion of our East Texas system into the Haynesville Shale.

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Segment gross margin also increased $11.2 million for the year ended December 31, 2012 as compared with the year ended December 31, 2011, due to improved recoveries of NGLs resulting from enhancements we made to increase the operating efficiency of several of the processing plants on our Anadarko system, a higher NGL content in the natural gas stream for natural gas we processed and the completion of our Allison processing plant.

Impact of Derivatives on Segment Gross Margin. Our gathering, processing and transportation business was negatively affected by unrealized, non-cash, mark-to-market net gains of approximately $3.7 million for the year ended December 31, 2012, compared to approximately $9.5 million of net gains recorded for the year ended December 31, 2011, representing a total decrease of approximately $5.8 million in segment gross margin associated with derivative instruments.

Operating and Maintenance. Operating and maintenance costs of our gathering, processing and transportation business were $40.5 million higher for the year ended December 31, 2012 when compared with the year ended December 31, 2011, primarily due to the following:

• Increased workforce related costs of approximately $8.4 million associated with the full year operation of the Allison processing plant in 2012, coupled with costs incurred to enhance and maintain the safety and operational efficiency of our systems;

• Increased costs of $12.9 million, of which approximately $8.2 million related to additional maintenance and supplies and $2.7 million for additional property taxes primarily resulting from the additional assets we placed into service during late 2011;

• Increased pipeline integrity costs of $6.1 million we incurred to ensure the ongoing safe and reliable operation of our existing plants, pipelines and related facilities; and

• $4.3 million of costs we expensed related to a development project on our East Texas system that we do not expect to complete until production levels reach a sustainable level to support our expansion activities in the region.

General and Administrative. General and administrative costs increased approximately $14.2 million for the year ended December 31, 2012 as compared with the year ended December 31, 2011, primarily due to the additional costs we are allocated for the services we share with other affiliates including, but not limited to, director and executive oversight, treasury, cash management, risk management, accounting, information technology and commercial services and the associated benefits and costs for the personnel that provide these services. The costs we are allocated for these services increase with the size and scope of our operating activities. Our allocated costs increased for the year ended December 31, 2012 compared with the year ended December 31, 2011 due to rising benefit costs, including higher pension expense due to lower discount rates, and an increased number of support service employees.

Depreciation and Amortization. Depreciation and amortization expense for the year ended December 31, 2012 was $7.2 million lower than depreciation expense for the year ended December 31, 2011. Effective July 1, 2011, we revised the depreciation rates for our gathering, processing and transportation business following the completion of a study to reassess the expected useful lives our property, plant and equipment, which resulted in a $17.0 million

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decrease in depreciation expense for the year ended December 31, 2012 as compared with the year ended December 31, 2011. The reduced rate of depreciation expense for 2012 was partially offset by additional depreciation associated with assets we placed in service in late 2011 and during 2012.

Year ended December 31, 2011 compared with year ended December 31, 2010

Segment Gross Margin. Segment gross margin for our gathering, processing and transportation business for the year ended December 31, 2011 increased by $122.9 million compared with the year ended December 31, 2010, primarily due to the acquisition of our Elk City assets in September 2010 coupled with higher NGL prices. For the year ended December 31, 2011, prices for natural gas decreased modestly, while NGL prices increased. Average natural gas prices decreased by approximately 8% per MMBtu for the year ended December 31, 2011 compared to the year ended December 31, 2010, based on the NYMEX Henry Hub pricing index. Average NGL prices increased by approximately 18% and 29% per composite barrel for the year ended December 31, 2011 compared to the year ended December 31, 2010, based upon the Conway and Mont Belvieu market hubs, respectively. These higher commodity prices positively impacted our segment gross margin by $58.9 million for the year ended December 31, 2011 compared with the year ended December 31, 2010.

For the year ended December 31, 2011, natural gas volumes on our systems increased approximately 402,000 MMBtu/d, or 17%, when compared with the year ended December 31, 2010, primarily due to production increases in the Granite Wash play and new assets placed in service to capture the production growth from the Haynesville Shale play. Volumes on our Anadarko system increased 42% for the year ended December 31, 2011 compared with the year ended December 31, 2010, the majority of which was associated with our acquisition of the Elk City system, which increased volumes on the system by an additional 185,000 MMBtu/d. Additionally, customers began to target more liquids-rich formations, primarily on our Anadarko system. This liquids-rich production, as well as our Elk City system acquisition, increased NGL production on our systems by approximately 13,729 Bpd, or 19%, for the year ended December 31, 2011 compared with the year ended December 31, 2010.

Due to our Elk City acquisition, we earned approximately $68.7 million of incremental segment gross margin during the year ended December 31, 2011 due to our expanded footprint in the Anadarko basin.

Although volumes were higher on the majority of our systems for the year ended December 31, 2011 compared with the year ended December 31, 2010, certain areas in which we operate experienced uncharacteristically cold weather and freezing precipitation during February 2011, with temperatures dropping below freezing for extended periods. These conditions resulted in mechanical issues with our customers’ equipment and adversely affected their ability to flow natural gas. Production volumes decreased during this period, which reduced the average daily throughput on our systems by approximately 14,000 MMBtu/d for the year ended December 31, 2011. Additionally, mechanical problems with two of our treating plants in East Texas required that they be taken out of service for extended periods during the first quarter of 2011. These adverse weather conditions, coupled with our plant downtime in East Texas, had an approximate $13.0 million negative impact to the segment gross margin of our gathering, processing and transportation business for year ended December 31, 2011.

Our segment gross margin generated from processing activities for the year ended December 31, 2011 was $41.5 million, representing a decrease of $24.4 million from the $65.9 million we generated for the year ended December 31, 2010. This decrease in segment gross margin generated from processing activities was a result of the rapid increase in production of liquids-rich natural gas on our Anadarko system, excluding our Elk City assets, where a majority of our contracts require processing of natural gas regardless of our available capacity. The negative impact from processing activities on our segment gross margin was largely attributable to paying natural gas customers for liquids we were unable to recover due to natural gas production exceeding our

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available processing capacity. Average daily volumes on our Anadarko system increased from 645,000 MMBtu/d to 762,000 MMBtu/d, or 18%, for the year ended December 31, 2011 compared with the year ended December 31, 2010, which exceeded our available processing capacity at the time. These capacity constraints were reduced by our acquisition of the Elk City system in September 2010, the completion of our Allison processing plant in November 2011 and the completion of additional NGL takeaway capacity in April 2012. The increase in natural gas production in the Anadarko basin is largely attributable to the relative increase in the average price of NGLs during 2011, which incentivized producers to increase drilling and production activities in regions with greater amounts of NGLs, such as the Anadarko basin and Eagle Ford Shale production areas.

Impact of Derivatives on Segment Gross Margin. Our gathering, processing and transportation business was positively affected by unrealized, non-cash, mark-to-market net gains of $9.5 million for the year ended December 31, 2011, compared to approximately $2.5 million of net gains recorded for the year ended December 31, 2010, representing a total increase of approximately $7.0 million in segment gross margin associated with derivative instruments.

Operating and Maintenance. Operating and maintenance expenses of our gathering, processing and transportation business were $49.6 million higher for the year ended December 31, 2011 compared with the year ended December 31, 2010, primarily due to the expansion of our East Texas system and our Anadarko system, including the Elk City system we acquired in September 2010. Operating and maintenance expenses associated with our Elk City system increased by approximately $28 million during the year ended December 31, 2011 compared to the year ended December 31, 2010, primarily because we owned the system for the entire year.

General and Administrative. General and administrative expenses increased $19.5 million for the year ended December 31, 2011 compared with the year ended December 31, 2010, primarily due to additional costs we were allocated as a result of growth in our asset base, including our Elk City assets.

Depreciation and Amortization. Depreciation and amortization expense for our gathering, processing and transportation business increased $7.0 million for the year ended December 31, 2011 compared with the year ended December 31, 2010, largely due to the added depreciation associated with the Elk City system we acquired in September 2010 and additional assets that we placed in service during 2010. This increase was partially offset by our revision of depreciation rates for our Anadarko, North Texas and East Texas systems effective July 1, 2011, which reduced depreciation and amortization expense by approximately $17.0 million. Our revised depreciation rates reflect an extension of the depreciable lives based on revised projections of the remaining lives of the natural gas production in the basins served by our assets.

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Logistics and Marketing

The following table sets forth the operating results of our logistics and marketing business for the periods presented:

	Three months ended March 31,						Year ended December 31,
	2013			2012			2012			2011		2010
	(in millions)
Operating revenues	$	1,198.1		$	1,306.0		$	4,539.9		$	6,914.0	$	6,055.8
Cost of natural gas and natural gas liquids		1,178.7			1,295.2			4,452.9			6,795.5		5,973.9
Segment gross margin		19.4			10.8			87.0			118.5		81.9
Operating and maintenance		19.2			20.8			80.8			76.8		57.5
General and administrative		2.6			10.3			19.1			10.1		11.2
Depreciation and amortization		1.7			1.8			7.0			7.5		4.3
Operating expenses		23.5			32.9			106.9			94.4		73.0
Operating income (loss)	$	(4.1	)	$	(22.1	)	$	(19.9	)	$	24.1	$	8.9

Three months ended March 31, 2013 compared with the three months ended March 31, 2012

Segment Gross Margin. The segment gross margin of our logistics and marketing business for the three months ended March 31, 2013 increased by $8.6 million when compared with the three months ended March 31, 2012. During 2013, the addition of logistics assets and the centralization of our marketing function to our corporate offices in Houston, Texas favorably impacted our segment gross margin by approximately $3.0 million for the three months ended March 31, 2013 compared with the three months ended March 31, 2012. In addition, our segment gross margin was impacted by a $3.4 million reduction in derivative losses described below. Additionally, segment gross margin for the three months ended March 31, 2012 was adversely affected by a $2.4 million non-cash charge, also referred to as a lower of cost or market adjustment, to reduce the cost basis of our natural gas inventory to net realizable value, which compares with a $0.8 million charge that affected the segment gross margin during the three months ended March 31, 2013. Since we hedge our storage positions financially, these charges are recovered when the physical natural gas inventory is sold or the financial hedges are realized.

Impact of Derivatives on Segment Gross Margin. Our logistics and marketing business was negatively affected by unrealized, non-cash, mark-to-market net losses of $2.9 million for the three months ended March 31, 2013, compared with $0.5 million of unrealized non-cash, mark-to-market net gains for the three months ended March 31, 2012, representing a total decrease of $3.4 million in segment gross margin associated with derivative instruments.

Operating and Maintenance. Operating and maintenance costs of our logistics and marketing business were $1.6 million lower for the three months ended March 31, 2013 compared with the three months ended March 31, 2012, primarily due to the retirement of a number of older trucks and trailers in 2011, which reduced our maintenance costs during the period, and the closure of a dispatch and maintenance facility associated with our trucking business and the consolidation of those activities at other locations.

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General and Administrative. General and administrative costs of our logistics and marketing business were $7.7 million lower for the three months ended March 31, 2013 compared with the three months ended March 31, 2012, primarily due to costs we incurred in 2012 for the investigation of accounting irregularities at our trucking and NGL marketing subsidiary. Please read “—Critical Accounting Policies and Estimates—Trucking and NGL Marketing Business Accounting Matters.”

Depreciation and Amortization. Depreciation and amortization expense for the three month period ended March 31, 2013 was slightly lower than depreciation and amortization expense for the three months ended March  31, 2012 due to the centralization of our marketing function to our corporate offices in Houston, Texas.

Year ended December 31, 2012 compared with year ended December 31, 2011

Segment Gross Margin. The segment gross margin of our logistics and marketing business was $31.5 million lower for the year ended December 31, 2012 compared with the year ended December 31, 2011, due to fewer opportunities to benefit from price differentials between market centers as a result of lower natural gas and NGL prices during 2012. Also contributing to the lower segment gross margin was the centralization of our marketing function to our corporate offices in Houston, Texas. We scaled back our logistics and marketing activities during this period to facilitate the orderly transition of these activities, and we began to gradually increase our logistics and marketing activities to previous levels during the fourth quarter of 2012.

Partially offsetting the decrease in segment gross margin was $11.7 million of segment gross margin realized from access to additional condensate stabilization facilities that our gathering, processing and transportation business placed into service during 2011, coupled with other assets we placed into service during 2012 to enable delivery of crude oil to barges from our crude oil pipeline, storage facility and barge loading facility near Mayersville, Mississippi.

Impact of Derivatives on Segment Gross Margin. Our logistics and marketing business was negatively affected by unrealized, non-cash, mark-to-market net losses of $2.5 million for the year ended December 31, 2012, compared to $7.0 million of net gains recorded for the year ended December 31, 2011, representing a total decrease of $9.5 million in segment gross margin associated with derivative instruments.

Operating and Maintenance. Operating and maintenance costs of our logistics and marketing business were $4 million higher for the year ended December 31, 2012 when compared with the year ended December 31, 2011, primarily due to additional assets placed into service during 2012 associated with the acquisition of our liquids rail loading facilities and integrity and environmental costs associated with our crude oil pipeline in Mississippi.

General and Administrative. General and administrative costs of our logistics and marketing business were $9 million higher for the year ended December 31, 2012 when compared with the year ended December 31, 2011, primarily due to costs we incurred in 2012 for the investigation of accounting irregularities at our trucking and NGL marketing subsidiary. Please read “—Critical Accounting Policies and Estimates—Trucking and NGL Marketing Business Accounting Matters.”

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Depreciation and Amortization. Depreciation and amortization expense for the year ended December 31, 2012 was slightly lower than depreciation and amortization expense for the year ended December  31, 2011.

Year ended December 31, 2011 compared with year ended December 31, 2010

Segment Gross Margin. The segment gross margin of our logistics and marketing business was $36.6 million higher for the year ended December 31, 2011, as compared with the year ended December 31, 2010, primarily due to the addition of logistics assets through our acquisition of a trucking company with operations in South Texas and East Texas in October 2010, as well as increased NGL transportation and storage spreads due to increasing NGL prices. Additionally, segment gross margin for the year ended December 31, 2011 was adversely affected by a $3.6 million lower cost or market adjustment we recorded to reduce the cost basis of our natural gas inventory to net realizable value.

Impact of Derivatives on Segment Gross Margin. Our logistics and marketing business was positively affected by unrealized, non-cash, mark-to-market net gains of $7.0 million for the year ended December 31, 2011, which is a $11.8 million increase compared with $4.8 million of net losses recorded for the year ended December 31, 2010. These amounts are associated with derivative instruments that do not qualify for hedge accounting treatment under the authoritative accounting guidance. These gains were primarily attributable to the realization of financial instruments used to hedge our storage and transportation positions.

Operating and Maintenance. Operating and maintenance costs of our logistics and marketing business were $19.3 million higher for the year ended December 31, 2011 when compared with the year ended December 31, 2010, primarily due to a full year of costs in 2011 related to our acquisition of a trucking company in October 2010, which increased our trucking and marketing operations in South and East Texas.

General and Administrative. General and administrative costs of our logistics and marketing business were $1.1 million lower for the year ended December 31, 2011 when compared with the year ended December 31, 2010.

Depreciation and Amortization. Depreciation and amortization expense for the year ended December 31, 2011 was $3.2 million higher than depreciation and amortization expense for the year ended December 31, 2010, primarily due to a full year of depreciation from our acquisition of a trucking company in October 2010, as well as other assets placed into service in 2010.

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Corporate Activities

Our corporate activities consist of interest expense, interest income, allowance for equity during construction and other costs such as income taxes, which are not allocated to our business segments.

	Three months ended March 31,						Year ended December 31,
	2013			2012			2012			2011			2010
	(in millions)
Operating revenues	$	—		$	—		$	—		$	—		$	—
Cost of natural gas and natural gas liquids		—			—			—			—			—
Segment gross margin		—			—			—			—			—
Operating and maintenance		—			—			—			—			—
General and administrative		—			—			0.2			0.1			0.4
Depreciation and amortization		—			—			—			—			—
Operating expenses		—			—			0.2			0.1			0.4
Operating loss		—			—			(0.2	)		(0.1	)		(0.4	)
Other income (expense)		0.1			(0.1	)		(0.1	)		2.8			3.0
Income tax expense		0.5			0.6			3.8			2.9			2.6
Net income (loss)	$	(0.4	)	$	(0.7	)	$	(4.1	)	$	(0.2	)	$	—

Three months ended March 31, 2013 compared with three months ended March 31, 2012

The interest cost we recognize is an allocation of EEP’s cost and is directly offset by the amount of interest cost we capitalize on outstanding construction projects. Historically, EEP incurred third-party interest costs, which we recognized to the extent we were able to capitalize such costs to our construction projects.

The following table sets forth our interest cost for the three months ended March 31, 2013 and 2012.

	March 31,
	2013		2012
	(in millions)
Interest expense	$	5.6	$	1.3
Interest capitalized		5.6		1.3
Interest cost incurred	$	—	$	—
Interest cost paid	$	5.6	$	1.3

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are typically borne by our partners through the allocation of taxable income.

Texas imposes taxes that are based upon many, but not all, items included in net income. Our income tax expense was $0.5 million for the three months ended March 31, 2013 compared to $0.6 million for the three months ended March  31, 2012.

Year ended December 31, 2012 compared with year ended December 31, 2011

Our corporate activities are primarily comprised of shared operating resources and financing activities we employ to operate our businesses. The net loss we experienced in 2012 from corporate activities was mostly attributable to the income taxes allocated to us by EEP with respect to our activities. In addition, during 2011 we recognized other income resulting from gain on the sale of a carbon dioxide plant and income derived from the favorable settlement of a lawsuit.

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For the year ended December 31, 2012, we capitalized $11.9 million to our construction projects compared with $3.3 million for the year ended December 31, 2011. The following table sets forth our interest cost for the years ended December 31, 2012 and 2011.

	December 31,
	2012		2011
	(in millions)
Interest expense	$	11.9	$	3.3
Interest capitalized		11.9		3.3
Interest cost incurred	$	—	$	—
Interest cost paid	$	11.9	$	3.3

Our income tax expense was $3.8 million for the year ended December 31, 2012 compared to $2.9 million for the year ended December 31, 2011.

Year ended December 31, 2011 compared with year ended December 31, 2010

The increase in our net income in 2011 was mostly attributable to an increase in other income resulting from gain on the sale of a carbon dioxide plant and income derived from the favorable settlement of a lawsuit.

The following table sets forth our interest cost for the years ended December 31, 2011 and 2010.

	December 31,
	2011		2010
	(in millions)
Interest expense	$	3.3	$	1.9
Interest capitalized		3.3		1.9
Interest cost incurred	$	—	$	—
Interest cost paid	$	3.3	$	1.9

Our income tax expense was $2.9 million for the year ended December 31, 2011 compared to $2.6 million for the year ended December 31, 2010.

Liquidity and Capital Resources

Historically, our sources of liquidity included cash generated from operations and funding from EEP. We were dependent upon EEP and its affiliates for our treasury services. Following this offering, we will have separate bank accounts, but EEP will provide treasury services on our general partner’s behalf under an intercorporate services agreement that we will enter into with EEP at the closing of this offering. Under the intercorporate services agreement, EEP has agreed to reduce the total general and administrative expenses that otherwise would be fully allocable to us by $25.0 million annually following the closing of this offering. Additionally, in connection with 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 to which Midcoast Operating is a party, which would otherwise require Midcoast Operating to provide letters of credit or other financial assurance.

We expect our ongoing sources of liquidity following this offering to include cash generated from operations of Midcoast Operating, borrowings under our revolving credit facility and issuances of additional debt

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and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

Revolving Credit Facility

In connection with our initial public offering, we will enter into a new $         million senior revolving credit facility. The revolving credit facility will be available to fund working capital and to finance acquisitions and other capital expenditures. Borrowings under our revolving credit facility are expected to bear interest at a rate equal to LIBOR plus an applicable margin. LIBOR and the applicable margin will be defined in our revolving credit facility agreement. We expect the unused portion of the revolving credit facility will be subject to an annual standby commitment fee.

We expect the revolving credit facility to contain covenants and conditions that, among other things, limit our ability to make cash distributions, incur indebtedness, create liens, make investments and enter into a merger or sale of substantially all of our assets. We also expect to be subject to certain financial covenants, including a consolidated leverage ratio and an interest coverage ratio, and customary events of default under the revolving credit facility.

Capital Expenditures

We categorize our capital expenditures as either maintenance or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are 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. We also include a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems as maintenance capital expenditures. We expect to incur continuing annual maintenance capital expenditures primarily for well-connects and for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital expenditures will increase due to the growth of our pipeline systems. We expect to fund maintenance capital expenditures through operating cash flows.

Expansion capital expenditures are those 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. We anticipate funding expansion capital expenditures temporarily through borrowings under our revolving credit facility, with long-term debt and equity funding being obtained when needed and as market conditions allow.

Following the closing of this offering, 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. As a result, if our interests in Midcoast Operating increase, our proportionate share of the maintenance capital expenditures incurred by Midcoast Operating will also increase proportionate to our interest in Midcoast Operating. Please read “—Future Growth Opportunities,” “Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Capital Expenditures” and “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Amended and Restated Limited Partnership Agreement of Midcoast Operating.”

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The following table sets forth our estimated maintenance and expansion capital expenditures for the year ending December 31, 2013. Although we anticipate making these expenditures in 2013, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets. For the year ending December 31, 2013, we anticipate our capital expenditures to approximate the following:

	Total 2013 Forecasted Expenditures
	(in millions)
Joint Venture Projects
Texas Express NGL system		185
Capital Projects
Beckville processing plant		26
Ajax processing plant		55
Other expansion capital expenditures		275
Maintenance capital expenditures		70
	$	611

For the three months ended March 31, 2013, we made capital expenditures of approximately $132.0 million in the aggregate.

Summary of Obligations and Commitments

The following table summarizes the principal amount of our obligations and commitments at December 31, 2012:

	2013		2014		2015		2016		2017		Thereafter		Total
	(in millions)
Purchase commitments(1)	$	83.6	$	—	$	—	$	—	$	—	$	—	$	83.6
Other operating leases		14.1		13.6		12.6		12.1		11.2		32.2		95.8
Rights-of-way(2)		0.8		0.6		0.5		0.7		0.5		12.2		15.3
Product purchase obligations(3)		16.1		15.2		9.8		—		—		—		41.1
Transportation/Service contract obligations(4)		35.6		43.4		42.4		39.5		79.0		551.2		791.1
Fractionation agreement obligations(5)		36.1		43.3		43.3		43.3		43.3		219.7		429.0
Total	$	186.3	$	116.1	$	108.6	$	95.6	$	134.0	$	815.3	$	1,455.9

(1) Represents commitments to purchase materials from third-party suppliers in connection with our growth projects.

(2) Rights-of-way payments are estimated to approximate $0.5 million to $0.8 million per year for the remaining life of our systems, which has been assumed to be 25 years for purposes of calculating the amount of future minimum commitments beyond 2017.

(3) We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at prices approximating market at the time of delivery.

(4) The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on the Texas Express NGL system and third-party pipelines and storage facilities.

(5) The fractionation agreement obligations represent the minimum payment amounts for firm fractionation of our NGL supply that we reserve at third party fractionation facilities.

The payments made under our obligations and commitments for the years ended December 31, 2012, 2011 and 2010 were $117.0 million, $98.4 million and $88.9 million, respectively.

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Cash Flow Analysis

Three months ended March 31, 2013 compared with three months ended March 31, 2012

	Three months ended March 31,						Variance 2013 vs  . 2012
	2013			2012
	(in millions)
Total cash provided by (used in):
Operating activities	$	109.3		$	142.3		$	(33.0	)
Investing activities		(111.8	)		(141.1	)		29.3
Financing activities		2.5			(1.2	)		3.7
Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of year		—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—

Operating Activities. Net cash provided by our operating activities decreased $33.0 million for the three months ended March 31, 2013, compared with the three months ended March 31, 2012. The decrease is primarily due to a $6.5 million decrease in net income coupled with changes in our working capital accounts of $27.6 million for the three months ended March 31, 2013 compared with the same period in 2012, inclusive of increases in natural gas and NGL storage inventory. Our working capital accounts were affected by changes in natural gas and NGL prices between periods, which affect the amount we accrue for natural gas and NGL sales and purchases, coupled with general timing differences in the collection on, and payment of, our current and related party accounts.

Investing Activities. Net cash used in our investing activities for the three months ended March 31, 2013 decreased by $29.3 million, compared with the same period in 2012, primarily due to a decrease in additions to property, plant and equipment of $35.5 million associated with the construction of the Ajax processing plant and other enhancement projects, which increased property, plant and equipment in 2012. Partially offsetting the decrease in additions to property, plant and equipment were increased contributions to fund the construction activities associated with the Texas Express NGL system of approximately $9.2 million for the three months ended March 31, 2013 when compared to the same period in 2012.

Financing Activities. The net cash provided by our financing activities increased $3.7 million during the three months ended March 31, 2013 compared with the same period in 2012, primarily due to lower distributions paid during the period.

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Cash Flow Analysis

Year ended December 31, 2012 compared with year ended December 31, 2011

	Year ended December 31,						Variance 2012 vs  . 2011
	2012			2011
	(in millions)
Total cash provided by (used in):
Operating activities	$	352.7		$	415.6		$	(62.9	)
Investing activities		(614.5	)		(480.1	)		(134.4	)
Financing activities		261.8			64.5			197.3
Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of year		—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—

Operating Activities. Net cash provided by our operating activities decreased $62.9 million for the year ended December 31, 2012, compared with the year ended December 31, 2011, primarily due to a $51.7 million decrease in net income coupled with changes in our working capital accounts of $19.6 million for the year ended December 31, 2012 compared with the same period in 2011. Our working capital accounts were affected by changes in natural gas and NGL prices between periods, which affect the amount we accrue for natural gas and NGL sales and purchases, coupled with general timing differences in the collection on, and payment of, our current and related party accounts.

Investing Activities. Net cash used in our investing activities for the year ended December 31, 2012 increased by $134.4 million, compared with the year ended December 31, 2011, primarily due to construction of the Ajax processing facility and other enhancement projects, which increased property, plant and equipment in 2012. We also made cash contributions of approximately $168.5 million during the year ended December 31, 2012 to fund construction activities associated with the Texas Express NGL system, in excess of the amounts funded in 2011.

Financing Activities. The net cash provided by our financing activities increased $197.3 million during the year ended December 31, 2012 compared with the year ended December 31, 2011, primarily due to an increase in capital contributions we received from our partners, which we used to finance our construction activities, which in turn were partially offset by lower distributions paid during 2012.

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Cash Flow Analysis

Year ended December 31, 2011 compared with year ended December 31, 2010

	Year ended December 31,						Variance
	2011			2010			2011 vs . 2010
	(in millions)
Total cash provided by (used in):
Operating activities	$	415.6		$	172.4		$	243.2
Investing activities		(480.1	)		(984.1	)		504.0
Financing activities		64.5			811.7			(747.2	)
Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of year		—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—

Operating Activities. Net cash provided by our operating activities increased $243.2 million for the year ended December 31, 2011, compared with the year ended December 31, 2010, primarily due to a $61.8 million increase in net income coupled with changes in our working capital accounts of $194.3 million for the year ended December 31, 2011 compared with the same period in 2010. Our working capital accounts were affected by changes in natural gas and NGL prices between periods, which affect the amount we accrue for natural gas and NGL sales and purchases, coupled with general timing differences in the collection on, and payment of, our current and related party accounts.

Investing Activities. Net cash used in our investing activities for the year ended December 31, 2011 declined by $504.0 million, compared with the year ended December 31, 2010, primarily due to our 2010 acquisition of the Elk City system for $686.1 million. Partially offsetting the overall decrease in investing activities for 2011 was $166.8 million of capital expenditures we made to expand our East Texas system into the Haynesville Shale and construct the Allison processing plant coupled with $10.7 million of cash contributions we made to fund construction activities associated with the Texas Express NGL system during 2011.

Financing Activities. The net cash provided by our financing activities decreased $747.2 million during the year ended December 31, 2011 compared with the year ended December 31, 2010, primarily due to a decrease in capital contributions that were made to us during 2010 to finance our acquisitions, which were partially offset by higher distributions paid during 2011.

Off Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

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Quantitative and Qualitative Disclosures About Market Risk

Our net income and cash flows are subject to volatility resulting from changes in the prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas and NGLs we purchase for processing. Our exposure to commodity price risk exists within each of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

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The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at March 31, 2013 and December 31, 2012.

	March 31, 2013													December 31, 2012
				Wtd. Average Price(2)					Fair Value(3)					Fair Value(3)
	Commodity	Notional(1)		Receive		Pay			Asset		Liability			Asset		Liability
Portion of contracts maturing in 2013
Swaps
Receive variable/pay fixed	Natural Gas		1,932,100	$	3.99	$	(3.54	)	$	0.9	$	(0.1	)	$	0.2	$	(0.3	)
	NGL		603,000	$	53.94	$	(50.61	)	$	2.0	$	—		$	1.4	$	—
	Crude Oil		396,550	$	96.78	$	(100.64	)	$	—	$	(1.5	)	$	0.2	$	(3.9	)
Receive fixed/pay variable	Natural Gas		3,634,500	$	4.92	$	(4.05	)	$	3.5	$	(0.4	)	$	7.8	$	—
	NGL		2,318,125	$	53.01	$	(52.03	)	$	8.0	$	(5.7	)	$	9.3	$	(9.9	)
	Crude Oil		1,320,225	$	92.00	$	(96.79	)	$	3.1	$	(9.4	)	$	6.3	$	(8.9	)
Receive variable/pay variable	Natural Gas		40,361,000	$	4.05	$	(4.03	)	$	1.0	$	(0.2	)	$	1.2	$	(0.2	)
Physical Contracts
Receive variable/pay fixed	NGL		830,000	$	40.87	$	(36.72	)	$	3.9	$	(0.5	)	$	0.6	$	(0.8	)
	Crude Oil		126,000	$	97.33	$	(96.14	)	$	0.3	$	(0.1	)	$	0.4	$	(0.4	)
Receive fixed/pay variable	NGL		1,593,115	$	39.04	$	(40.87	)	$	0.5	$	(3.4	)	$	2.6	$	(2.2	)
	Crude Oil		195,000	$	95.72	$	(97.42	)	$	0.1	$	(0.5	)	$	0.3	$	(1.0	)
Receive variable/pay variable	Natural Gas		38,822,722	$	4.06	$	(4.05	)	$	0.6	$	(0.5	)	$	0.9	$	—
	NGL		7,164,820	$	40.23	$	(39.85	)	$	5.4	$	(2.7	)	$	5.2	$	(2.3	)
	Crude Oil		1,167,990	$	100.18	$	(98.52	)	$	4.4	$	(2.4	)	$	6.4	$	(3.0	)
Portion of contracts maturing in 2014
Swaps
Receive variable/pay fixed	Natural Gas		21,870	$	4.31	$	(5.22	)	$	—	$	—		$	—	$	—
	NGL		60,000	$	82.95	$	(85.26	)	$	—	$	(0.1	)	$	—	$	—
	Crude Oil		506,255	$	92.75	$	(101.95	)	$	—	$	(4.6	)	$	—	$	(4.9	)
Receive fixed/pay variable	Natural Gas		2,496,900	$	4.01	$	(4.20	)	$	—	$	(0.5	)	$	0.2	$	—
	NGL		892,425	$	63.63	$	(62.10	)	$	3.0	$	(1.6	)	$	0.9	$	(2.7	)
	Crude Oil		1,361,955	$	94.22	$	(92.79	)	$	5.1	$	(3.1	)	$	5.4	$	(2.8	)
Receive variable/pay variable	Natural Gas		8,112,500	$	4.31	$	(4.30	)	$	0.2	$	(0.1	)	$	0.1	$	(0.1	)
Physical Contracts
Receive variable/pay variable	Natural Gas		21,409,275	$	4.33	$	(4.32	)	$	0.5	$	(0.4	)	$	0.5	$	—
	NGL		4,182,500	$	18.23	$	(18.27	)	$	—	$	(0.2	)	$	—	$	—
Portion of contracts maturing in 2015
Swaps
Receive variable/pay fixed	Crude Oil		515,015	$	89.33	$	(100.93	)	$	—	$	(5.9	)	$	—	$	(5.6	)
Receive fixed/pay variable	NGL		109,500	$	88.36	$	(77.40	)	$	1.2	$	—		$	0.7	$	(0.2	)
	Crude Oil		865,415	$	97.72	$	(89.33	)	$	7.3	$	(0.1	)	$	6.8	$	(0.2	)
Physical Contracts
Receive variable/pay variable	Natural Gas		8,468,425	$	4.34	$	(4.30	)	$	0.4	$	(0.1	)	$	0.4	$	—
Portion of contracts maturing in 2016
Swaps
Receive fixed/pay variable	Crude Oil		45,750	$	99.31	$	(86.97	)	$	0.6	$	—		$	0.5	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		783,240	$	4.50	$	(4.38	)	$	0.1	$	—		$	0.1	$	—

(1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbls.

(2) Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

(3) The fair value is determined based on quoted market prices at March 31, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses and $0.2 million of losses at March 31, 2013 and December 31, 2012, respectively.

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The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at March 31, 2013 and December 31, 2012.

	At March 31, 2013													At December 31, 2012
	Commodity	Notional(1)		Strike Price(2)		Market Price(2)			Fair Value(3)					Fair Value(3)
									Asset		Liability			Asset		Liability
Portion of option contracts maturing in 2013
Puts (purchased)	Natural Gas		1,237,500	$	4.18	$	(3.99	)	$	0.5	$	—		$	1.4	$	—
	NGL		367,000	$	31.90	$	(28.34	)	$	2.7	$	—		$	3.7	$	—
Portion of option contracts maturing in 2014
Puts (purchased)	NGL		264,250	$	52.46	$	(50.87	)	$	2.4	$	—		$	1.3	$	—
Calls (written)	NGL		136,500	$	54.17	$	(40.34	)	$	—	$	(0.4	)	$	—	$	—

(1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbls.

(2) Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.

(3) The fair value is determined based on quoted market price at March 31, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective period to consider the time value of money.

Hedge Accounting

We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply the market approach to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value.

In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in cost of natural gas and natural gas liquids for our commodity-based derivatives. Cash flow is only affected to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in cost of natural gas and natural gas liquids for commodity hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever

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possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Non-Qualified Hedges

Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in cost of natural gas and natural gas liquids in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.

The following transaction types do not qualify for hedge accounting and contribute to the volatility of our income and cash flows:

Commodity Price Exposures:

• Transportation—In our logistics and marketing business, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.

• Storage—In our logistics and marketing business, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas is recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas storage activities can create volatility in our earnings.

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• Optional Natural Gas Processing Volumes—In our gathering, processing and transportation business, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Our processing facilities provide us with the ability to reject ethane during periods in which it is economic for us to do so. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

• NGL Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. In the second quarter of 2009, we determined that a sub-group of physical NGL sales contracts with terms allowing for economic net settlement did not qualify for the normal purchases and normal sales, or NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.

• Natural Gas Forward Contracts—In our logistics and marketing business, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In the first quarter of 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.

• Natural Gas Options—In our gathering, processing and transportation business, we use options to hedge the forecasted commodity exposure of our NGLs and natural gas. Although options can qualify for hedge accounting treatment under authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of NGLs and natural gas until the underlying transactions are settled.

In all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income in cost of natural gas and natural gas liquids.

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The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net unrealized gains and losses associated with the changes in fair value of our derivative financial instruments:

	March 31,						December 31,
	2013			2012			2012			2011			2010
	(in millions)
Gathering, processing and transportation segment
Hedge ineffectiveness		0.5			(1.8	)		3.1			(5.3	)		3.5
Non-qualified hedges		0.9			3.2			0.6			14.8			(1.0	)
Logistics and Marketing
Non-qualified hedges		(2.9	)		0.5			(2.5	)		7.0			(4.8	)
Derivative fair value net gains (losses)		(1.5	)		1.9			1.2			16.5			(2.3	)

Derivative Positions

Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:

	March 31,			December 31,
	2013			2012			2011
	(in millions)
Other current assets		254.1			275.0			153.9
Other assets, net		68.2			78.1			122.0
Accounts payable and other		(245.3	)		(259.9	)		(168.3	)
Other long-term liabilities		(64.0	)		(78.0	)		(131.1	)
		13.0			15.2			(23.5	)

The changes in the net assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of long-term natural gas, NGL and crude oil sales and purchase contracts.

We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $2.7 million and $3.6 million as of March 31, 2013 and December 31, 2012, respectively, associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the three month period ended March 31, 2013, no realized commodity hedge amounts were de-designated as a result of the hedges no longer meeting hedge accounting criteria. During the years ended December 31, 2012 and 2011, unrealized commodity hedge losses of $6.3 million and $6.9 million, respectively, were de-designated as a result of the hedges no longer meeting the hedge accounting criteria. We estimate that there will be no financial impact from the reclassification from AOCI to earnings during the next twelve months for any unrealized net losses or gains from our cash flow hedging activities based on pricing and positions at March 31, 2013. We estimate that approximately $4.2 million, representing unrealized net gains from our cash flow hedging activities based on pricing and positions at December 31, 2012, will be reclassified from AOCI to earnings during the next 12 months.

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds

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are met pursuant to the terms of Midcoast Operating’s International Swaps and Derivatives Association, Inc., or ISDA^®, financial contracts, Midcoast Operating has the right to require collateral from its counterparties. Midcoast Operating would include any cash collateral received in the balances listed above, however, as of March 31, 2013, December 31, 2012 and 2011, Midcoast Operating are holding no cash collateral on its asset exposures. When Midcoast Operating is in a position of posting collateral to cover its counterparties’ exposure to its non-performance, the collateral is provided through letters of credit, which are not reflected above.

The ISDA^® agreements and associated credit support, which govern Midcoast Operating’s financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of Midcoast Operating’s outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA^® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if Midcoast Operating is in a liability position to its counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

The ISDA^® agreements, in combination with Midcoast Operating’s master netting agreements, and credit arrangements governing Midcoast Operating’s interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. EEP generally provides letters of credit to satisfy such collateral requirements under Midcoast Operating’s ISDA^® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When Midcoast Operating is holding an asset position, its counterparties are likewise required to post collateral on their liability (Midcoast Operating’s asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

In the event that EEP’s consolidated credit ratings were to decline to the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, Midcoast Operating may be required to provide additional amounts under its existing letters of credit to meet the requirements of its ISDA^® agreements. For example, if EEP’s consolidated credit ratings had been at the lowest level of investment grade at December 31, 2012, Midcoast Operating would not have been required to provide additional letters of credit. In connection with 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 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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Recent Accounting Pronouncements

Accounting Standards Update—Balance Sheet Offsetting

In December 2011, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities, or ASU 2011-11, as part of the FASB’s joint project with the IASB, which requires an entity to disclose information about financial instruments and derivative financial instruments that have been offset within the balance sheet, or are subject to a master netting arrangement or similar agreement, regardless of whether they have been offset within the balance sheet. In January 2013, the FASB issued Accounting Standards Update No. 2013-01 to clarify the scope of transactions subject to the disclosure provisions of ASU 2011-11 include derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria established under U.S. GAAP, or that are subject to a master netting arrangement or similar agreement. The objectives of the standards are to allow financial statement users to understand the effect that offsetting of financial instruments and derivative financial instruments have on an entity’s financial position. Both standards are effective for interim and annual reporting periods beginning on or after January 1, 2013, with required disclosures presented retrospectively for all comparative period presented. The adoption of this pronouncement has not had a material impact on our consolidated financial statements.

Accounting Standards Update—Accumulated Other Comprehensive Income

In February 2013, the FASB issued Accounting Standards No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, or ASU 2013-02, which requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component, but does not change the current requirements for reporting net income or other comprehensive income in financial statements. ASU 2013-02 requires presentation of significant amounts reclassified out of accumulated other comprehensive income into earnings by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The standard is effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. The adoption of this pronouncement has not had a material impact on our financial statements.

Accounting Standards Update—Liabilities

In February 2013, the FASB issued Accounting Standards No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, or ASU 2013-04. The provisions of ASU 2013-04 require measurement of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of (1) the amount the reporting entity agreed to pay on the basis of its arrangement among co-obligors and (2) any additional amount the reporting entity expects to pay on behalf of its co-obligors. Additionally, ASU 2013-04 requires disclosure of the nature and amount of the obligation as well as information about such obligations. The provisions of ASU 2013-04 are effective for fiscal years beginning after December 15, 2013, and interim periods within those years and should be applied retrospectively to all prior periods presented, with early adoption permitted. We do not expect to early adopt the provisions of this standard, nor do we expect our adoption to have a material effect on our financial statements.

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Critical Accounting Policies and Estimates

Our selection and application of accounting policies is an important process that has developed as our business activities have evolved and as new accounting pronouncements have been issued. Accounting decisions generally involve an interpretation of existing accounting principles and the use of judgment in applying those principles to the specific circumstances existing in our business. We make every effort to comply with all applicable accounting principles and believe the proper implementation and consistent application of these principles is critical. However, not all situations we encounter are specifically addressed in the accounting literature. In such cases, we must use our best judgment to implement accounting policies that clearly and accurately present the substance of these situations. We accomplish this by analyzing similar situations and the accounting guidance governing them and consulting with experts about the appropriate interpretation and application of the accounting literature to these situations.

In addition to the above, certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures with respect to contingent assets and liabilities. The basis for our estimates is historical experience, consultation with experts and other sources we believe to be reliable. While we believe our estimates are appropriate, actual results can and often do differ from these estimates. Any effect on our business, financial position, results of operations and cash flows resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

We believe our critical accounting policies and estimates discussed in the following paragraphs address the more significant judgments and estimates we use in the preparation of our consolidated financial statements. Each of these areas involve complex situations and a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that affect our consolidated financial statements. Our management has discussed the development and selection of the critical accounting policies and estimates related to the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent liabilities with the Audit, Finance & Risk Committee of Enbridge Management’s board of directors.

Trucking and NGL Marketing Business Accounting Matters

EEP previously identified a material weakness in our internal control over financial reporting with respect to our wholly owned trucking and NGL marketing subsidiary related to intentional misconduct and collusion of local management and staff that resulted in accounting misstatements. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. EEP did not maintain an effective control environment at our wholly owned trucking and NGL marketing subsidiary and our monitoring of the effectiveness of those controls at that subsidiary was not sufficient to deter or detect that they had been circumvented.

EEP’s management, with the participation of the EEP’s principal executive officer and principal financial officer, implemented changes to our internal control over financial reporting related to the referenced subsidiary to remediate the material weakness described above. The following changes to our control environment and monitoring of controls and internal controls as it relates to the referenced subsidiary were implemented:

• EEP appointed replacements for management at the subsidiary, who separated from the organization.

• A new accounting manager of the subsidiary was appointed.

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• EEP implemented new centralized reporting structures for various groups, including risk management and information technology which were relocated to our corporate office.

• EEP centralized critical control functions, including accounting, contract administration, and risk management into our corporate office.

• EEP retrained all of the personnel in addition to our ongoing annual training process at the referenced subsidiary on EEP’s statement of Business Conduct, Whistleblower, and Conflicts of Interest policies.

• EEP implemented additional process and monitoring controls including review over reconciliations and financial performance addressing completeness, existence, accuracy and valuation of our revenue, cost of natural gas and natural gas liquids, payables, receivables and inventory. EEP implemented information technology controls over the reconciliation of key systems to ensure completeness, existence and accuracy of key financial data.

EEP’s management has completed the documentation and testing of the remediation measures described above and, as of December 31, 2012, has concluded that the steps taken have remediated the material weakness.

Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas and Natural Gas Liquids

In general, we recognize revenue when delivery has occurred or services have been rendered, pricing is determinable and collectability is reasonably assured. For our gathering, processing and transportation and logistics and marketing businesses, we must estimate our current month revenue and cost of natural gas and natural gas liquids to permit the timely preparation of our consolidated financial statements. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data prior to preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and cost of natural gas and natural gas liquids based on the best available volume and price data for natural gas and NGLs delivered and received, along with a true-up of the prior month’s estimate to equal the prior month’s actual data. As a result, there is one month of estimated data recorded in our operating revenues and cost of natural gas and natural gas liquids for each period reported. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the consistency of our processes.

Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment

We capitalize expenditures related to property, plant and equipment, subject to a minimum rule, that have a useful life greater than one year for: (1) assets purchased or constructed; (2) existing assets that are replaced, improved or the useful lives have been extended; or (3) all land, regardless of cost. Acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt, and, in our regulated businesses that apply the authoritative accounting provisions applicable to regulated operations, an equity return component.

We categorize our capital expenditures as either core maintenance or enhancement expenditures. Core maintenance expenditures are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment that are worn, obsolete or near the end of their useful lives. Examples of core maintenance expenditures include valve automation programs, cathodic protection, zero-hour compression overhauls and electrical switchgear replacement programs. Enhancement expenditures improve the

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service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues, and enable us to respond to governmental regulations and developing industry standards. Examples of enhancement expenditures include costs associated with installation of seals, liners and other equipment to reduce the risk of environmental contamination from crude oil storage tanks, costs of sleeving, or replacing, a major segment of a pipeline system following an integrity tool run, natural gas or crude oil well-connects, natural gas plants and pipeline construction and expansion. We also began including a portion of our capital expenditures for well-connects associated with our natural gas system assets as core maintenance expenditures beginning in 2009.

Regulatory guidance issued by the FERC requires us to expense certain costs associated with implementing the pipeline integrity management requirements of the United States Department of Transportation’s Office of Pipeline Safety. Under this guidance, costs to: (1) prepare a plan to implement the program; (2) identify high consequence areas; (3) develop and maintain a record keeping system; and (4) inspect, test and report on the condition of affected pipeline segments to determine the need for repairs or replacements, are required to be expensed. Costs of modifying pipelines to permit in-line inspections, certain costs associated with developing or enhancing computer software and costs associated with remedial mitigation actions to correct an identified condition continue to be capitalized. We typically expense the cost of initial in-line inspection programs, crack detection tool runs and hydrostatic testing costs conducted for the purposes of detecting manufacturing or construction defects consistent with industry practice and the regulatory guidance issued by the FERC. However, we capitalize initial construction hydrostatic testing costs and subsequent hydrostatic testing programs conducted for the purpose of increasing pipeline capacity in accordance with our capitalization policies. Also, capitalized are certain costs such as sleeving or recoating existing pipelines, unless the expenditures are incurred as a single event and not part of a major program, in which case we expense these costs as incurred.

We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the crude oil or natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

We record depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities. Under the group method, for all segments, upon the disposition of property, plant and equipment, the net book value less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we recognize a gain or loss in our consolidated statements of income for the difference between the cash received and the net book value of the assets sold. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. At regular intervals, we retain the services of independent consultants to assist us with assessing the reasonableness of the useful lives we have established for the property, plant and equipment of our major systems. Based on the results of these assessments we may make modifications to the assumptions we use to determine our depreciation rates.

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active

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markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

Assessment of Recoverability of Goodwill

Goodwill represents the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is included with both of our reportable segments.

Pursuant to the authoritative accounting provisions for goodwill and other intangible assets, we do not amortize goodwill, but test it for impairment annually based on carrying values as of the end of the second quarter, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may be impaired. In testing goodwill for impairment, we make critical assumptions that include but are not limited to: (1) projections of future financial performance, which include commodity price and volume assumptions, (2) the expected growth rate of our gathering, processing and transportation business and our logistics and marketing business, (3) residual values of the assets; and (4) market weighted average cost of capital. Impairment occurs when the carrying amount of a reporting unit’s goodwill exceeds its implied fair value. We reduce the carrying value of goodwill to its fair value at the time we determine that an impairment has occurred.

Assessment of Recoverability of Intangibles

Our intangible assets consist primarily of customer contracts for the purchase and sale of natural gas, natural gas supply opportunities and contributions we have made in aid of construction activities that will benefit our operations, as well as workforce contracts and customer relationships. We amortize these assets on a straight-line basis over the weighted average useful lives of the underlying assets, representing the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

We evaluate the carrying value of our intangible assets whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability of intangibles, we compare the carrying value to the undiscounted future cash flows we expect the intangibles or the underlying assets to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangibles and its carrying amount exceeds its fair value, we write the intangibles down to their fair value.

Derivative Financial Instruments

Our net income and cash flows are subject to volatility stemming from changes in commodity prices of natural gas, NGLs, condensate, crude oil and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas and natural gas liquids we purchase for processing. In order to manage the risks to unitholders, we use a variety of derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to create offsetting positions to specific commodity exposures. We do not have any material exposure to movements in foreign exchange rates as virtually all of our revenues and expenses are denominated in United States dollars, or USD. To the extent that a material foreign exchange exposure arises, we intend to hedge such exposure using derivative financial instruments. In accordance with the authoritative accounting guidance, we record all derivative financial instruments to our consolidated statements of financial position at fair market value. We record the fair market value of our derivative financial instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a net basis by counterparty. Derivative balances are shown net of cash collateral received or posted where master netting agreements exist. For those instruments that qualify for hedge accounting under authoritative accounting guidance, the accounting

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treatment is dependent on the intended use and designation of each instrument. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income to cost of natural gas and natural gas liquids.

Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of Enbridge Management or a committee of senior management of our general partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction and we do not use derivative financial instruments for speculative purposes.

Derivative financial instruments qualifying for hedge accounting treatment that we use are cash flow hedges. We enter into cash flow hedges to reduce the variability in cash flows related to forecasted transactions.

Price assumptions we use to value our non-qualifying derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from OTC market makers to find executable bids and offers. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective, and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

We record the changes in fair value of derivative financial instruments designated and qualifying as effective cash flow hedges as a component of “Accumulated other comprehensive income” until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized immediately in earnings.

Our earnings are also affected by use of the mark-to-market method of accounting as required under United States Generally Accepted Accounting Principles, or U.S. GAAP, for derivative financial instruments that do not qualify for hedge accounting. We use derivative financial instruments such as basis swaps and other similar derivative financial instruments to economically hedge market price risks associated with inventories, firm commitments and certain anticipated transactions. However, these derivative financial instruments do not qualify for hedge accounting treatment under authoritative accounting guidance, and as a result we record changes in the fair value of these instruments on the statement of financial position and through earnings rather than deferring them until the firm commitment or anticipated transactions affect earnings. The use of mark-to-market accounting for derivative financial instruments can cause non-cash earnings volatility resulting from changes in the underlying indices, primarily commodity prices.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value to our derivative instruments associated with our commodity activities. We define fair value as an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

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We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

• Level 1—We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments.

• Level 2—We categorize the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument, as Level 2. This category includes both over-the-counter, or OTC, transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted prices for assets and liabilities; (b) time value; (c) volatility factors; and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

• Level 3—We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources. (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include debt and derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: non-binding broker quotes, time value, volatility, correlation and extrapolation methods.

The approximate fair values of our long-term debt obligations are determined using a standard methodology that incorporates pricing points that are obtained from independent third party investment dealers who actively make markets in our debt securities, which we use to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding.

We utilize a mid-market pricing convention, or the “market approach,” for valuation as a practical expedient for assigning fair value to our derivative assets and liabilities. Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation, and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities. We present the fair value of our derivative contracts net of cash paid or received pursuant to collateral agreements on a net-by-counterparty basis in our consolidated statements of financial position when we believe a legal right of setoff exists under an enforceable master netting agreement. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

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Commitments, Contingencies and Environmental Liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in “Operating and maintenance” expense in our consolidated statements of income and “Other long-term liabilities” in our consolidated statements of financial position at their undiscounted amounts. We always have the potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

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INDUSTRY OVERVIEW

General

Midstream services are a critical part of the natural gas value chain. Natural gas gathering and processing systems create value by collecting raw natural gas from the wellhead and separating dry gas (primarily methane) from NGLs such as ethane, propane, normal butane, isobutane and natural gasoline. A significant proportion of natural gas produced at the wellhead contains NGLs. Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from gas wells. This “rich,” unprocessed, natural gas is generally not acceptable for transportation in the nation’s interstate transmission pipeline system or for commercial use. Processing plants extract the NGLs, leaving residual dry gas that meets interstate transmission pipeline and commercial quality specifications. The extracted NGLs themselves are marketable commodities and, on an energy equivalent basis, usually have a greater economic value as a raw material for petrochemicals and motor gasolines than as a component of the natural gas stream.

The following diagram illustrates the groups of assets commonly found along the natural gas and NGL value chains:

The range of services offered by midstream service providers are generally divided into the following categories:

Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to individual wellheads in the production area. Natural gas gatherers may also install larger diameter pipelines to connection points, referred to as central receipt points, where producers can connect their wells or gathering infrastructure. These systems typically gather raw natural gas to central locations for processing and/or treating. A large gathering system may involve thousands of miles

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of gathering lines connected to thousands of wells and multiple central receipt points. Gathering systems are often designed to be highly flexible and scalable to allow gathering of natural gas at different pressures, to flow natural gas to multiple plants and to quickly connect new customers to allow for additional production without significant incremental capital expenditures. Midstream service providers generally charge a fixed fee to gather raw natural gas.

Compression. Since wells produce at progressively lower field pressures as they deplete, it becomes increasingly difficult to produce the remaining reserves against a higher pressure that exists in the connecting gathering system. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to flow into a higher pressure system. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure from the compressor to deliver natural gas into a higher pressure pipeline system. If field compression is not installed, then the remaining natural gas will not be produced if it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering natural gas that otherwise would not be produced. Consequently, gathering systems that operate at lower pressures or that can provide tiered compression service often have a competitive advantage over high-pressure gathering systems. Midstream service providers typically provide compression services in exchange for a fixed fee or a percentage of the applicable commodity for fuel, or a combination of the two.

Treating and Dehydration. Raw natural gas contains various contaminants, such as water vapor, carbon dioxide and hydrogen sulfide, that can render the gas unacceptable for transmission on intrastate and interstate pipelines. In addition, end users will not purchase natural gas with an unacceptable level of these contaminants. To meet downstream pipeline and end-user natural gas quality standards, natural gas is dehydrated to remove water vapor and is chemically treated to separate carbon dioxide and hydrogen sulfide from the gas stream to the extent required. Midstream service providers generally charge a fixed fee, and may also retain a percentage of the natural gas for use as fuel in the treating plant, to treat and dehydrate natural gas.

Processing. Once the contaminants are removed, the next step involves the extraction of NGLs from the natural gas stream through a procedure known as processing. Most decontaminated natural gas with a significant NGL content is not suitable for long-haul pipeline transportation or commercial use and must be processed to extract the heavier hydrocarbon components in order to meet pipeline specifications. The separation of heavier hydrocarbons during processing is possible because of the differences in physical properties between the components of the raw gas stream. The three basic types of natural gas processing methods are cryogenic expansion, lean oil absorption and refrigeration, including hydrocarbon dewpoint refrigeration, or HCDP. Cryogenic expansion represents the latest generation of processing, incorporating extremely low temperatures and high pressures to provide the best processing and most economical extraction of NGLs.

Natural gas is processed not only to remove NGLs that would interfere with pipeline transportation or the end use of the residue gas, but also to separate from the natural gas those hydrocarbon liquids that could have a higher value as NGLs than as part of the natural gas stream. The principal components of residue gas are methane and ethane, but processors typically have the option either to recover ethane from the natural gas stream for processing into NGLs or reject ethane and leave it in the natural gas stream, depending on whether the ethane is more valuable as a separate commodity or left in the natural gas stream. The residue gas is sold to industrial, commercial and residential customers and electricity generators. The premium or discount in value between natural gas and separated NGLs is known as the “frac spread.” Because NGLs often serve as substitutes for products derived from crude oil, NGL prices tend to correlate with crude prices.

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Natural gas processing occurs under a contractual arrangement between the producer or owner of the raw natural gas stream and the processor. There are many forms of processing contracts used in the industry and specific commodity exposure to natural gas or NGL prices is highly dependent on the types of contracts entered into. Processing contracts can vary in length from one month to the “life of the lease.” Four typical processing contract types are described below:

• Fee-Based. In a fee-based arrangement, the processor receives a fee per Mcf of natural gas processed or per gallon of NGLs produced. Under this arrangement, a processor has no direct commodity price exposure.

• Percentage-of-Proceeds. In a percentage-of-proceeds arrangement, the processor receives a negotiated percentage of the natural gas and NGLs that it processes in the form of residue natural gas, NGLs, condensate and sulfur, which the processor can then sell at market prices and retain the proceeds as its compensation. This type of arrangement exposes the processor to commodity price risk, as the revenues from percentage-of-proceeds contracts directly correlate with the market prices of the applicable commodities that the processor receives.

• Percentage-of-Liquids. In a percentage-of-liquids arrangement, the processor receives a negotiated percentage of the NGLs extracted from natural gas that requires processing, which the processor can then sell at market prices and retain the proceeds as its compensation. This contract structure is similar to percentage-of-proceeds arrangements except that the processor receives only a percentage of the NGLs produced. This type of contract may also require a processor to provide the customer with a guaranteed NGL recovery percentage regardless of actual NGL production. Since revenues from percentage-of-liquids contracts directly correlate with the market price of NGLs, this type of arrangement also exposes the processor to commodity price risk.

• Keep-Whole/Wellhead Purchase. In a keep-whole/wellhead purchase arrangement, the processor gathers or purchases raw natural gas from the customer. The processor extracts and retains the NGLs produced during processing for its own account, which it then sells at market prices. In instances where the processor purchases raw natural gas at the wellhead, the processor may also sell the resulting residue gas for its own account at market prices. In those instances when the processor gathers and processes raw natural gas for the customer’s account, the processor generally must return to the customer residue gas with an energy content equivalent to the original raw natural gas the processor received, as measured in Btus. This type of arrangement has the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are dependent on the price of NGLs sold. As a result, a processor with these types of contracts benefits when the value of the NGLs is high relative to the cost of the natural gas and is disadvantaged when the cost of the natural gas is high relative to the value of the NGLs.

Fractionation. Fractionation is the separation of the heterogeneous mixture of extracted NGLs, sometimes referred to as “o-grade,” “x-grade,” “y-grade” or “raw make” NGLs, into individual components for end-use sale. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products. As the temperature of the stream is increased, the lightest component boils off the top of the distillation tower as a gas where it then condenses into a purity liquid that is routed to storage. The heavier components in the mixture are routed to the next tower where the process is repeated until all components have been separated. A typical barrel of NGLs consists of ethane, propane, normal butane, isobutane and natural gasoline. Described below are the basic NGL components and their typical uses:

• Ethane. Ethane is used primarily as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.

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• Propane. Propane is used as heating fuel, engine fuel and industrial fuel, for agricultural burning and drying and as petrochemical feedstock for production of ethylene and propylene.

• Normal Butane. Normal butane is principally used for motor gasoline blending and as fuel gas, either alone or in a mixture with propane, and feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane is also used to derive isobutane.

• Isobutane. Isobutane is principally used by refiners to enhance the octane content of motor gasoline and in the production of MTBE, an additive in cleaner burning motor gasoline.

• Natural Gasoline. Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.

Midstream service providers generally charge a per-gallon fee for fractionation services and return the resulting NGLs to customers or purchase the NGLs for resale.

Transportation and Storage. Once the raw natural gas has been treated or processed or the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. The natural gas industry and the NGL industry have hundreds of thousands of miles of intrastate and interstate transmission pipelines in addition to a network of barges, rails, trucks, terminals and storage to deliver raw NGLs or purity NGL products to market. The bulk of the NGL storage capacity is located near the refining and petrochemical complexes of the Texas and Louisiana Gulf Coasts, with a second major concentration in central Kansas. Each commodity system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts. There are two forms of contracts utilized in the transportation and storage of natural gas and NGLs:

• Firm. Firm transportation service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the actual volumes of natural gas or NGLs transported. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.

• Interruptible. Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas or NGLs actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.

Market Fundamentals

Natural Gas Supply and Demand

As indicated in the chart shown below, U.S. natural gas production and overall U.S. energy demand are expected to grow in the coming decades. Population is a large determinant of energy consumption through its influence on demand for travel, housing, consumer goods and services. According to the U.S. Energy Information Administration, or EIA, energy use is projected to grow by approximately 10% from 2011 to 2040. Energy use per capita is expected to decline by approximately 15% while the total U.S. population is expected to increase by an estimated 29% from 2011 to 2040. Over the course of the next five years, energy use is expected to increase approximately 3%. A discussion of other supply and demand elements follows.

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Natural gas is a key component of energy consumption within the United States. According to the EIA, annual consumption of natural gas in the United States increased from approximately 24.3 quadrillion Btu in 2010 to approximately 24.8 quadrillion Btu in 2011. According to the EIA, natural gas consumption represented approximately 25% of total energy consumption in 2011, and the EIA projects that this percentage will increase to approximately 27% by 2040. The charts shown below illustrate energy consumption by fuel source in 2011 and expected energy consumption by fuel source in 2040.

The EIA expects that the growth of natural gas consumption relative to other fuel sources will be primarily driven by the use of natural gas electricity generation. According to the EIA, demand for natural gas in the electric power sector is projected to increase from approximately 7.6 Tcf in 2011 to approximately 9.5 Tcf in 2040, with a portion of the growth attributable to the retirement of 49 gigawatts of coal-fired capacity by 2022. The EIA also projects that natural gas consumption in the industrial sector will be higher due to the rejuvenation of the industrial sector as it benefits from increasing shale gas production that is accompanied by slow price growth, particularly from 2011 through 2019, when the price of natural gas is expected to remain below 2010 levels. However, the EIA expects growth in natural gas consumption for power generation and in the industrial sector is to be partially offset by decreased usage in the residential sector related primarily to decreased demand for natural gas powered home heating.

U.S. Primary Energy Consumption by Fuel, 1980—2040

Source: EIA, Annual Energy Outlook 2013 (January 2013).

In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of natural gas must continue to be developed to support consumption rates. Over the past several years, there has been a fundamental shift in U.S. natural gas production towards unconventional resources, defined by the EIA as natural gas produced from shale formations and coal beds. The emergence of unconventional natural gas plays and advancements in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of natural gas from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale gas production. As indicated by the diagram below, the development of these unconventional sources has offset declines in other, more traditional U.S. natural gas supply sources, which has helped meet growing consumption and lowered the need for imported natural gas. In fact, the EIA predicts that the U.S. will become a net exporter of natural gas starting in 2020.

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As indicated by EIA forecasts shown in the diagram below, as the depletion of conventional onshore and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the disparity and continue to gain market share from higher-cost sources of natural gas. In fact, the EIA estimates that natural gas production from the major shale formations will provide the majority of the growth in domestically produced natural gas supply in coming years, increasing to approximately 50% in 2040 as compared with 34% in 2011. According to the EIA, shale gas will be the largest contributor to natural gas production growth, while production from tight sands, coalbed methane deposits and offshore waters is expected to remain stable.

U.S. Dry Natural Gas Production by Source, 1990 – 2040

Source: EIA, Annual Energy Outlook 2013 (January 2013).

Recently, the price of natural gas has rebounded from historically low levels, with prompt month NYMEX natural gas futures prices reaching $4.09 per MMBtu as of May 31, 2013, compared to a spot price low of $1.82 per MMBtu in April 2012 and a high of $13.31 per MMBtu in July 2008. Additionally, the current range of forward month NYMEX natural gas futures through December 2017 is $4.09 and $4.95 per MMBtu. This compares to an average of $3.28 per MMBtu in 2012. The recent recovery in prices is the result of a moderation in gas drilling and increased demand, as well as an extended winter that has resulted in less gas in storage than the five-year average.

NGL Supply and Demand

A majority of the U.S. NGL supply comes from gas processing plants. The majority of gas processing plants in the U.S. are located along the U.S. Gulf Coast and in the Mid-Continent and Rockies regions. Smaller gas processing regions are located in Michigan and Illinois, as well as the Marcellus region and Southern California. In Canada, the majority of the processing capacity is located in Alberta, with a smaller amount in British Columbia.

NGL products from refineries are by-products of refinery processes. As a result, they have generally already been separated into individual components and do not require further fractionation. NGL products from

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refineries are principally propane, with lesser amounts of butane, refinery naphthas (products similar to natural gasoline) and ethane. Due to refinery maintenance schedules and seasonal demand considerations, refinery production of propane and butane varies on a seasonal basis. NGLs are also imported into certain regions of the United States from Canada and other parts of the world. NGLs (primarily propane) are also exported from certain regions of the United States.

NGL supplies from gas processing plants are increasing rapidly due to the increased drilling activity in unconventional resource plays, where producers are targeting “liquids rich” areas to capitalize on forecasted high relative NGL product prices. The EIA projects NGL supply volumes will continue to grow over 40% in the next decade from 2.2 MMBbls/d in 2011 to 3.1 MMBbls/d by 2020. A significant amount of this volume is expected to come from recently discovered unconventional resource plays, which do not typically have the NGL infrastructure to process the wet natural gas or transport, fractionate, and store the NGL products. As a result of these dynamics, substantial incremental infrastructure is likely to be developed throughout the NGL value chain over the next several years, and traditional regional basis relationships could change significantly. A portion of the increased supply of NGLs will likely be absorbed by the domestic petrochemical sector as feedstocks. In addition, growing production of Canadian heavy crude oil is likely to create demand for additional diluents, primarily natural gasoline and butane. The remaining product not absorbed domestically will likely drive continued growth in the NGL export market. Due to rapid increases in NGL production, the prices of NGLs (particularly ethane and propane) have experienced downward pressure. The expectation of additional NGL supply is one of the key drivers for new NGL consumption and infrastructure development such as chemical plants, propane dehydrogenation facilities and export markets.

Key Basins in Which We Operate

Anadarko Basin

The Anadarko basin is one of the most prolific natural gas-producing basins in the United States, spanning from western Oklahoma to the northeast portion of the Texas Panhandle. The basin is approximately 56,000 square miles with roughly 54,000 producing wells as of December 2012, according to Wood Mackenzie, an energy research and consulting firm. Although mature and long-lived, the Anadarko Basin has recently been the focus of increased exploration activity. Oil development in the Anadarko basin has been cyclical, with early activity in the late 1990s and early 2000s focusing on oil exploitation and gas production. In addition, the basin benefits from established infrastructure, favorable fiscal terms and a supportive regulatory environment. Wood Mackenzie reports that, since 2009, operators have been exploring the basin’s rich gas fields and older, conventional oil fields with horizontal laterals and enhanced technology, vastly improving recoveries and opening up previously uneconomic plays.

Granite Wash Play. The Granite Wash play extends through the northern portion of the Texas Panhandle and into Western Oklahoma, within the Anadarko basin. The play’s most attractive characteristic is its multi-pay potential, which is provided by many stacked sand zones. Key producing formations include the Cottage Grove and Hogshooter Limestone formations. The advent of horizontal drilling brought renewed interest to the Granite Wash play, with operators focusing on its liquid-rich gas stream, both in the form of oil and NGLs.

Mississippi Lime Play. The Mississippi Lime play, which underlies the Anadarko basin, is located primarily within the Mid-Continent area and covers approximately 36,000 square miles across northern Oklahoma and southern and western Kansas. The formation has a relatively shallow depth, ranging from 3,000 to 6,500 feet. As of August 2012, there were approximately 700 horizontal wells drilled in the area, according to Wood Mackenzie.

East Texas Basin

The East Texas basin is a large hydrocarbon basin extending from several counties around Tyler, Texas, east into northern Louisiana and southern Arkansas. Production in the East Texas basin began with the discovery

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of the massive East Texas Oil Field in 1930. With improvements in drilling and completion technology, several additional prospective areas have been exploited. The basin contains the Cotton Valley sandstone formation, one of the largest natural gas fields in the continental United States prior to the 2006 discovery of the Haynesville Shale play, also located in the East Texas basin. Natural gas production from the Cotton Valley formation has produced a total of 21.5 Tcf of natural gas since 1968, according to Wood Mackenzie. Natural gas exploitation activity from the Haynesville Shale play has produced a total of 7.0 Tcf of natural gas with aggressive production beginning in 2008, according to Wood Mackenzie. Even though drilling activity in the Haynesville Shale play has recently slowed (since most core acreage is held by production), drilling activity is expected to increase if natural gas prices increase from current levels. Presently, the most active horizontal drilling target in the basin is the Cotton Valley formation due to attractive liquids yields. In addition, the East Texas basin benefits from established infrastructure, favorable fiscal terms and a supportive regulatory environment.

Cotton Valley. The Cotton Valley formation covers an area of approximately 33,400 square miles and is located in east Texas and northern Louisiana. The formation has been producing since 1968 and still holds significant reserve and resource potential. According to Wood Mackenzie, the Cotton Valley formation is one of the most productive tight gas plays in the continental United States. Development originally focused on conventional Cotton Valley Sands, but production is now dominated by the tight permeability sections of the reservoir. Abundant well data have made this play one of the most attractive tight gas targets. Current operational focus is primarily on infill drilling in established fields. Activity in the Cotton Valley formation is primarily focused in Caddo and DeSoto parishes in Louisiana and Panola and Rusk counties in Texas, where the natural gas production typically has a higher liquids content.

Haynesville Shale. The Haynesville Shale play encompasses 5,800 square miles and is found in northwestern Louisiana, southwestern Arkansas and eastern Texas. It is considered to be the second largest natural gas shale formation in the United States by production, after the Marcellus Shale play. The play was discovered in 2006 and gained popularity with operators in 2008 due to the large supply of gas trapped within portions of the shale combined with improved recovery techniques. According to Wood Mackenzie, the Haynesville Shale play is between 10,500 and 13,500 feet in depth and is overlain by sandstone of the Cotton Valley formation and underlain by limestone of the Smackover formation. The play is marked by high temperatures and high pressure, and contains low amounts of carbon dioxide and hydrogen sulfide, according to Wood Mackenzie.

Bossier Shale. The Bossier Shale play covers an area of approximately 3,300 square miles and is primarily located in eastern Texas and northwestern Louisiana. The play overlies nearly 50% of the Haynesville Shale and shares many of the same geologic traits that make the Haynesville Shale a prolific reservoir. According to Wood Mackenzie, the Bossier Shale play is thought to have large volumes of gas-in-place and presents attractive development opportunities in higher price environments. Due to its overlapping nature, the Bossier Shale play is seen as an upside play to the Haynesville Shale.

Fort Worth Basin

The Fort Worth basin is a large hydrocarbon basin covering more than ten counties in North Central Texas extending into Southern Oklahoma. Production began with the exploitation of Bend Conglomerate and Strawn Sandstone reservoirs in the early 1900s. Today, the Fort Worth basin is mainly known as the location of the Barnett Shale play, which covers approximately 3,400 square miles and was the first resource play to exploit blanket horizontal drilling in an area previously thought to be unproductive.

Barnett Shale. The Barnett Shale play is one of the largest and most mature natural gas fields in North America. Located primarily in the Fort Worth basin of North Texas, the “core” region of the Barnett Shale play has produced a total of 9.1 Tcf of natural gas since 1981, according to Wood Mackenzie. The Barnett Shale play underlies the Pennsylvanian Marble Falls formation and overlies the water-bearing Ordovician Ellenberger formation. The Barnett Shale play was discovered in 1981, but only significantly developed in the late 1990s due

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to technological advancements in recovery techniques. Although primarily a natural gas field, the Barnett Shale play also includes oil and condensate.

The Barnett Shale play has been classified into “core” and “non-core” areas of production. To date, production is concentrated in the core area, where the shale is thicker and recovery uncertainty is reduced. According to Wood Mackenzie, operators believe the Barnett Shale play provides low risk drilling opportunities due to the maturity of the play. Recent activity has been focused on developing the liquids rich area of the play, with additional upside potential believed to exist in the southwest portion of the Barnett Shale play in higher gas price environments.

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BUSINESS

Overview

We are a growth-oriented Delaware limited partnership recently formed by EEP to serve as EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. 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.

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 Bcf/d, including 350 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;

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• our TexPan liquids railcar facility near Pampa, Texas;

• 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” 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 U.S. GAAP.

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.

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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.

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.

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The following map shows the locations of our Anadarko, East Texas and North Texas systems and the Texas Express NGL mainline:

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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.

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 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;

• 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

• an approximately 30-mile propylene pipeline extending from Exxon’s refinery in Chalmette, Louisiana to an interconnecting Chevron pipeline near Lafitte, Louisiana.

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;

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• 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.

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. For example, we are currently engaged in the construction of the following organic growth projects:

• An additional cryogenic processing plant, which we refer to as our Ajax processing plant, and related facilities on our Anadarko system. The Ajax processing plant has a planned capacity of 150 MMcf/d and is intended to meet anticipated growth in customer processing needs resulting from increased horizontal drilling activity in the Granite Wash play in the Anadarko basin. The Ajax processing plant is anticipated to be placed into service during the third quarter of 2013.

• Our Texas Express NGL system, which is comprised of a 35% interest in two joint ventures with third parties that together are currently constructing a 580-mile NGL intrastate transportation mainline and approximately 116 miles of gathering lines. The system is expected

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to begin service during the third quarter of 2013. The mainline will have an initial capacity of approximately 280,000 Bpd and will be expandable to approximately 400,000 Bpd with the addition of intermediate pump stations on the system. We expect the Texas Express NGL system 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.

• A new cryogenic processing plant, which we refer to as our Beckville processing plant, on our East Texas system. The Beckville processing plant 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. The Beckville processing plant is expected to be placed into service during early 2015.

• 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, which we believe will, over the long-term, increase the attractiveness and profitability of our natural gas and NGL systems and attract new customers and increase our business with existing customers. We seek to capitalize on opportunities to attract new customers, increase volumes of natural gas and NGLs that we gather, 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. At the closing of this offering, we will enter into a new $             million revolving credit facility that is expected to be used to fund near-term growth and provide liquidity. We intend to finance long-term growth projects and acquisitions with a balanced combination of debt and equity that we believe will, together with our balanced capital structure, promote the long-term stability of our business.

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. These producing formations contain both dry natural gas and liquids rich zones. 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. We believe that continued drilling activity in these areas also positions us to further develop and optimize our assets and acquire complementary assets within our geographic footprint. We are one of the primary

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midstream operators in each of the natural gas basins in which we conduct business, and also one of the largest producers of NGLs in the United States.

• 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. For the years ending December 31, 2013 and 2014, we have hedged approximately 70% and 35%, respectively, of our expected NGL equity volumes with a combination of swaps and puts for the specific NGL components to which we are exposed.

• 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. Following this offering, EEP will own our general partner, a     % limited partner interest in us and all of our incentive distribution rights, as well as a 61% non-controlling interest in Midcoast Operating. 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. We believe that EEP and Enbridge will provide us with strategic guidance and expertise that will enhance our ability to grow our business.

• 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 have made significant commitments in downstream transportation and fractionation capacity to ensure access to the most attractive demand markets for our customers. 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.

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.

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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.”

Gathering, Processing and Transportation

Our gathering, processing and transportation business includes approximately 11,400 miles of natural gas gathering and transportation lines and approximately 222 miles of NGL gathering and transportation lines primarily located in Texas and Oklahoma, two of the most active natural gas drilling states in the United States. Our natural gas systems are located in basins that have experienced active drilling over the last several years. These core basins are known as the Anadarko basin, the East Texas basin and the Fort Worth basin. A substantial majority of our revenues are derived from gathering, compressing, dehydrating, treating, processing, fractionating and marketing the natural gas, NGLs and condensate that flow through our pipelines. Our joint venture Texas Express NGL system consists of 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. Our Anadarko, East Texas and North Texas natural gas systems and the Texas Express NGL system are described below.

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Anadarko System

General. Our Anadarko system is one of the largest gas gathering systems in the Anadarko basin and gathers natural gas production from multiple lean and rich formations. Our Anadarko system has experienced considerable growth as a result of the rapid development of the Granite Wash play. The Granite Wash play experienced a rapid increase in drilling activity beginning in late 2009 due to the increasing use by natural gas producers of horizontal drilling and multistage hydraulic fracturing techniques developed for shale plays. Our Anadarko system gathers natural gas from various producing formations in the Granite Wash play, including the Atoka, Hogshooter and Cleveland formations. For the year ended December 31, 2012 and the three months ended March 31, 2013, our Anadarko system had average daily volumes of approximately 1,017,000 MMBtu and 964,000 MMBtu of natural gas, respectively.

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The following map identifies the locations of the principal assets comprising our Anadarko system:

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Our Anadarko system consists of approximately 2,950 miles of natural gas gathering and transportation pipelines and 27 miles of residue gas pipelines, eight active processing plants, one processing plant currently under construction and three standby processing plants and one standby treating plant that can be converted to active status from time to time based on demand. The Anadarko system’s pipelines range from four to 20 inches in diameter and were generally constructed after 1970. The system has active processing capacity of approximately 860 MMcf/d and active condensate stabilization capacity of approximately 7,380 Bpd. In addition, at our Sweetwater plant, we also operate a second processing skid that is owned by a third party and for which we receive monthly operating fees. We are permitted to use this facility to process our volumes to the extent the owner does not utilize the full processing capacity. Our Anadarko system also includes 285 compressor units with approximately 442,000 total horsepower and 1,712 receipt meters from which it receives natural gas.

The following table sets forth additional information regarding our Anadarko system processing and treating plants:

Plant	Year Constructed / Upgraded		Gas Capacity (MMcf/d)			Type of Plant
Processing Plants
Ajax(1)(2)		2013		150		Cryogenic
Allison		2012		150		Cryogenic
Elk City(2)		1984		150		Cryogenic
Hidetown(2)		2008		120		Cryogenic
Hobart 277		1996		25		Cryogenic
Hobart JT(3)		2007		50		HCDP
Hobart Ranch A(3)		1975		30		Cryogenic
Hobart Ranch B		1994		25		Cryogenic
Nine Mile(2)		2010 / 2012		120		Cryogenic
Osborne(3)		2005		25		Refrigeration
Sweetwater(2)		2006 / 2011		120	(4)	Cryogenic
Zybach(2)		2005		150		Cryogenic
Total				1,115
Treating Plant
Prentiss(3)		1999		150		—

(1) Currently under construction.

(2) Plant includes a condensate stabilizer.

(3) Plant is currently on standby status and may be converted to active status from time to time based on demand.

(4) Excludes a second processing skid at the plant that is owned by a third party. We receive a weekly operating fee for operating the processing skid on behalf of such third party.

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Volumes on our Anadarko system have increased since 2010, primarily related to the acquisition of our Elk City assets in September 2010. The following table sets forth, for each of the years in the three-year period ended December 31, 2012 and the three months ended March 31, 2013, the average daily natural gas volumes on our Anadarko system and the average Henry Hub spot price for natural gas:

Anadarko System Volumes(2)

(1) As quoted by Inside FERC (Henry Hub F.O.M.) for the applicable period.

(2) Average daily volumes for the three months ended March 31, 2013 and the years ended December 31, 2012, 2011 and 2010 include 268,000 MMBtu/d, 225,000 MMBtu/d, 251,000 MMBtu/d and 66,000 MMBtu/d, respectively, of volumes associated with our Elk City system. We acquired the Elk City system in September 2010.

Natural Gas Supply. Our Anadarko system includes production from the Granite Wash tight sand formation. Productive horizons in the Granite Wash play include the Hogshooter, Checkerboard, Cleveland, Skinner, Red Fork, Atoka and Morrow formations. Favorable pricing for NGLs relative to natural gas has encouraged producers to increase production in the Granite Wash play due to the high NGL and condensate content. As of March 31, 2013, approximately 3,600 wells and 1,695 central receipt points were connected to our Anadarko system. These Anadarko basin wells generally have long lives with predictable flow rates. Natural gas is supplied to our Anadarko system by over 120 upstream customers, including customers such as Chesapeake Energy Corporation, or Chesapeake, Linn Energy, LLC, Devon Energy Corporation, Samson Lone Star LLC, Apache Corporation and Forest Oil Corporation, or their various affiliates which together represented over 65% of the system’s natural gas supply for the year ended December 31, 2012. Our principal competitors in the Anadarko basin are DCP Midstream, Enogex LLC, Eagle Rock Energy Partners, L.P., PVR Partners, L.P. and MarkWest Energy Partners, L.P., or MarkWest.

The natural gas supplied to our Anadarko system is generally dedicated to us under individually negotiated contracts. Most of our contracts have an initial term of at least five years. Following the initial term, these contracts generally are renewed for additional terms or continue on a month-to-month or year-to-year basis unless terminated by us or the customer. As of May 1, 2013, the volume weighted-average remaining life of our Anadarko system contracts is approximately 2.7 years. We gather and process natural gas under a combination of percentage-of-liquids fixed recovery, or POL, contracts, wellhead purchase/keep-whole contracts and fee-based contracts.

Recent Activity in the Anadarko Basin. Within the last 12 months, the rig count in the Anadarko basin has fluctuated between 67 and 91 active rigs, according to Rig Data. As of May 2013, our customers had 23 rigs drilling on acreage dedicated to us in the basin. Producers are pursuing wells with higher condensate and oil production relative to historical activity that was focused on lower-valued gas prospects. In 2011 and 2012, we added 99 and 98 new central receipt points directly connected to our Anadarko system, respectively. During the first quarter of 2013 we added 22 new central receipt points to our Anadarko system.

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Recent Growth Projects and Future Growth Opportunities. In response to the increased supply of natural gas and NGLs and the increased demand for our services in the Anadarko basin, we expanded our Anadarko system by acquiring the Elk City system for $686.1 million in cash in September 2010. At the time we acquired it, the Elk City system included one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 MMcf/d. This acquisition enhanced the processing capacity and expansion capability of our Anadarko system, enabling us to process greater volumes of natural gas resulting from the increased production in the Granite Wash play. Following the acquisition of our Elk City assets, we improved the processing capabilities of two of the acquired plants through the addition of enhanced refrigeration and cryogenic capabilities to improve ethane recoveries with richer natural gas.

We have recently undertaken several initiatives to further alleviate the capacity constraints resulting from the increasing supplies of natural gas in the areas served by our Anadarko system. We constructed a cryogenic processing plant, which we refer to as the Allison processing plant, that was placed into service in November 2011 to accommodate increased demand for our services resulting from increased horizontal drilling activity in the Granite Wash play. Additional NGL takeaway capacity at the Allison processing plant was also completed in April 2012. We are currently constructing an additional processing plant and other facilities, including compression and gathering infrastructure, on our Anadarko system, which we refer to as our Ajax processing plant, that we anticipate will be placed into service upon completion of the Texas Express NGL mainline in the third quarter of 2013. We estimate that the total cost of the Ajax processing plant will be approximately $230 million and expect that the Ajax processing plant, when operational, will increase the total processing capacity on our Anadarko system by approximately 150 MMcf/d to approximately 1,115 MMcf/d and will also increase the system’s condensate stabilization capacity by approximately 2,000 Bpd.

Markets for Sale of Natural Gas, NGLs and Condensate. Our Anadarko system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the Mid-Continent and Gulf Coast regions of the United States. All of our owned residue gas and condensate is sold to our logistics and marketing business. A portion of our owned NGLs is sold directly to OneOk Partners, L.P. (“ONEOK”), while the remainder is sold to our logistics and marketing business. The NGLs produced at our Anadarko system processing plants are transported by pipeline to third party fractionation facilities and NGL market hubs in Conway, Kansas and Mont Belvieu, Texas.

East Texas System

General. Our East Texas system is one of the largest gas gathering systems in the East Texas basin and gathers natural gas production from multiple proven formations, including lean, rich and oily formations. For the year ended December 31, 2012 and the three months ended March 31, 2013, our East Texas system had average daily volumes of approximately 1,266,000 MMBtu and 1,252,000 MMBtu of natural gas, respectively.

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The following map identifies the locations of the principal assets comprising our East Texas system:

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Our East Texas system consists of approximately 3,850 miles of natural gas gathering and transportation pipelines and approximately 108 miles of NGL pipelines, six active processing plants, including two HCDP plants, 10 active treating plants, three of which are leased from third parties and one standby treating plant that can be converted to active status from time to time based on demand. The East Texas system’s pipelines consist of approximately 400 miles of 24-inch and 36-inch pipeline with the remaining comprised of smaller diameter pipeline. The substantial majority of the large diameter 24-inch and 36-inch pipeline on our East Texas system was constructed after 2001, and most of our smaller-diameter pipelines were generally constructed after 1970. The system has active processing capacity of approximately 735 MMcf/d, active treating capacity of approximately 1,255 MMcf/d and active condensate stabilization capacity of approximately 2,650 Bpd. The system also includes 129 compressor units with approximately 198,000 total horsepower and over 811 receipt meters from which it receives natural gas.

The following table sets forth additional information regarding our East Texas system processing and treating plants:

Plant	Year Constructed / Upgraded	Gas Capacity (MMcf/d)		Type of Plant
Processing Plants
Avinger	1973 / 2013		80	Cryogenic
Beckville(1)	2013		150	Cryogenic
Grapeland	2007		200	HCDP
Henderson I	2006		120	Cryogenic
Henderson II	2007		150	HCDP
Longview(2)	1981 / 2000		120	Cryogenic
Trinidad	1975 / 2004		65	Cryogenic
Total			885
Treating Plants
Aker	1996		275	—
Aker Expansion	2007		125	—
Pittsburg	1982		70	—
Indian Rock	1996		75	—
Marquez	2006		200	—
NGPL(3)	2010		30	—
Plum Creek(4)	1996		80	—
Shelby	2012		150	—
Teague	1981		140	—
Tenaha(3)	2011		130	—
TET Zider(3)	2011		60	—
Total			1,335

(1) Plant is currently under construction. We expect that the Beckville processing plant will commence service during early 2015.

(2) Includes approximately 3,000 Bpd of produced NGLs that are fractionated at our Longview fractionation facility.

(3) Leased from a third party under service agreements that provide for 100% of the treating capacity for varying terms.

(4) Plant is currently on standby status and may be converted to active status from time to time based on demand.

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Volumes on our East Texas system have been relatively flat for the past three years despite a volatile natural gas price environment. In a higher natural gas price environment in 2008, volumes reached a peak of 1,479,000 MMBtu/d. The following table sets forth, for each of the years in the three-year period ended December 31, 2012 and the three months ended March 31, 2013, the average daily natural gas volumes on our East Texas system and the average Henry Hub spot price for natural gas:

East Texas System Volumes

(1) As quoted by Inside FERC (Henry Hub F.O.M.) for the applicable period.

Natural Gas Supply. Our East Texas system gathers production from the Cotton Valley Lime and lean Bossier Shale plays, which are located on the western side of our East Texas system; the Haynesville/Bossier Shale plays, which run from western Louisiana into East Texas and are among the largest natural gas resources in the United States; and the Cotton Valley Sand formation, which also runs from western Louisiana into East Texas and has a high content of NGLs and condensate on the eastern side of our East Texas system. The East Texas basin also includes multiple other natural gas and oil formations that are frequently explored, including the Woodbine, Travis Peak, James Lime, Rodessa, and Pettite, among other formations. As of March 31, 2013, approximately 5,600 wells and 811 central receipt points were connected to our East Texas system. These wells generally have long lives with predictable flow rates. Natural gas is supplied to our East Texas system by over 150 upstream customers, including large, integrated and independent oil and gas companies such as Exxon Mobil Corporation, EOG Resources, Inc., Chesapeake or their various affiliates, which together represented approximately 50% of the system’s natural gas supply for the year ended December 31, 2012. Our principal competitors in the East Texas basin are DCP Midstream, LLC, Enterprise Products Partners L.P. (“Enterprise Products Partners”), MarkWest, CenterPoint Energy, Inc. and Tenaska.

The natural gas supplied to our East Texas system is generally initially dedicated to us under individually negotiated contracts. Most of our contracts have an initial term of at least five years. Following the initial term, these contracts generally are renewed for additional terms or continue on a month-to-month or year-to-year basis unless terminated by us or the customer. In addition, some of our contracts are for the life of the lease. As of May 1, 2013, the volume weighted-average remaining life of our East Texas system contracts is approximately 5 years. We gather and process natural gas under a combination of POL processing contracts, fee-based contracts, wellhead purchase/keep-whole contracts, demand-based ship-or-pay contracts and percentage-of-index (“POI”) gas purchase contracts. Under a POI contract, we purchase raw natural gas at a negotiated percentage of an agreed upon index price and then resell the natural gas, generally for the index price, keeping the difference as our fee.

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Recent Activity in the East Texas Basin. Over the past 12 months, the rig count in the East Texas basin has fluctuated between 47 and 61 active rigs, according to Rig Data. As of May 2013, our customers had 15 rigs drilling on acreage dedicated to us in the basin. While dry gas drilling declined with the historical decreases in gas prices, more recently, drilling activity has increased in the basin by customers pursuing rich gas formations using horizontal drilling and multistage fracturing. In 2011 and 2012, we added 63 and 32 new central receipt points directly connected to our East Texas system, respectively. During the first quarter of 2013, we added five new central receipt points to the East Texas system.

Recent Growth Projects and Future Growth Opportunities. Since 2010, we have completed construction of approximately 155 miles of 8” to 24” gathering and transmission pipelines and added a total of six treating skids to capture production resulting from the significant increase in drilling activity in the Haynesville and Bossier Shale plays in East Texas near the Louisiana border. Throughput on this pipeline system averaged 400 MMcf/d for the three month period ended March 31, 2013.

Additionally, we completed modifications to our Longview plant’s recompression equipment and our Trinidad processing plant’s gathering system in October 2012 and March 2013, respectively, in order to improve efficiencies and increase NGL recoveries. We are also currently in the process of upgrading our Avinger processing plant to increase NGL recoveries. The upgrading of our Avinger processing plant is expected to be completed in early 2014.

We are also initiating construction of our new Beckville processing plant in East Texas to provide processing services to existing and prospective customers in the rich Cotton Valley formation. We expect that our Beckville processing plant will be capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs. We expect that the plant will commence service during early 2015 at an estimated cost of approximately $140.0 million.

Markets for Sale of Natural Gas, NGLs and Condensate. Our East Texas system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the U.S. Gulf Coast. In addition, we deliver pipeline-quality gas at over 40 locations, including some of the most significant intrastate and interstate pipelines in the U.S. Gulf Coast, as well as to several wholesale customers. The majority of our owned residue gas is sold to our logistics and marketing business, while the remainder of our owned residue gas is sold directly to third-party wholesale customers or utilities. All of our owned condensate is sold to our logistics and marketing business. A portion of the NGLs produced at one of our East Texas system processing plants is fractionated by us and sold directly to a third-party chemical company. The remainder of the NGLs recovered at our plants are sold to our logistics and marketing business and transported by pipeline to Mont Belvieu, Texas for fractionation.

North Texas System

General. Our North Texas system is located in the Fort Worth basin and gathers production from the Barnett Shale play. The Fort Worth basin is a mature basin with stable production and relatively low drilling and completion costs. The Barnett Shale area of the Fort Worth basin became one of the more active natural gas plays in North America starting in the late 1990s. While abundant natural gas reserves have been known to exist in the Barnett Shale play since the early 1980s, technological advances in fracturing the shale formation have allowed commercial production of these natural gas reserves. For the year ended December 31, 2012 and the three months ended March 31, 2013, our North Texas system had average daily volumes of approximately 330,000 MMBtu and 332,000 MMBtu of natural gas, respectively.

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The following map identifies the locations of the principal assets comprising our North Texas system:

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Our North Texas system consists of approximately 4,600 miles of natural gas gathering pipelines, 70 miles of residue gas pipelines and 60 miles of NGL pipelines, six active processing plants and one standby processing plant that can be converted to active status from time to time based on demand. The North Texas system’s pipelines range from four to 16 inches in diameter and were generally constructed after 1970. The system has active processing capacity of approximately 255 MMcf/d and an average condensate stabilization capacity of approximately 4,130 Bpd at our Springtown plant. The system also includes 155 compressor units with approximately 170,000 total horsepower and 2,258 receipt meters.

The following table sets forth additional information regarding our North Texas system processing plants:

Plant	Year Constructed / Upgraded	Gas Capacity (MMcf/d)		Type of Plant
Processing
Gordon	1973 / 2013		40	Cryogenic
Huckabay	1974		20	Cryogenic
Lone Camp	1975		40	Cryogenic
Pueblo(1)	1978		20	Cryogenic
Springtown(2)	1970 and 1978 / various upgrades		80	Cryogenic
Weatherford I	2007		35	Cryogenic
Weatherford II	2007		40	Cryogenic
Total			275

(1) Plant is currently on standby status and may be converted to active status from time to time based on demand.

(2) Plant includes a condensate stabilizer with 4,000 Bpd of NGL capacity.

Based on the latest information available for 2012, Barnett Shale production has increased from approximately 110 MMcf/d in 1999 to approximately 5,700 MMcf/d in August 2012. We believe that producers will continue their drilling and completion activities in the core areas served by our North Texas system 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. We expect a significant increase in drilling activity in the Barnett Shale play if natural gas prices further improve.

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As a result of relatively low natural gas prices during the past three years when compared to 2008, volumes on our North Texas system have declined slightly since 2010. In a higher gas price environment in 2008, volumes reached a peak of 395,000 MMBtu/d. The following table sets forth, for each of the years in the three-year period ended December 31, 2012 and the three months ended March 31, 2013, the average daily natural gas volumes on our North Texas system and the average Henry Hub spot price for natural gas:

North Texas System Volumes

(1) As quoted by Inside FERC (Henry Hub F.O.M.) for the applicable period.

Natural Gas Supply. A substantial portion of natural gas on our North Texas system is produced in the Barnett Shale play within the Fort Worth basin. As of March 31, 2013, approximately 3,400 wells and 2,258 central receipt points were connected to our North Texas system. These wells are located in the Fort Worth basin and generally have long lives with predictable flow rates. Natural gas is supplied to our North Texas system by over 350 upstream customers, including customers such as Enervest Operating, LLC, XTO Energy Inc., Atlas Barnett, LLC, Brigadier Operating LLC, Devon Gas Services, L.P., NextEra Energy Inc., Premier Energy Services Inc., Ray Richey & Company, Inc. and ConocoPhillips Company, or their various affiliates, which together represented over 40% of the system’s natural gas supply for the year ended December 31, 2012. Our principal competitors in the North Texas basin are Targa Resources Partners, LP (“Targa Resources Partners”), Crosstex Energy LP, Energy Transfer Partners, L.P. (“Energy Transfer Partners”) and DCP Midstream.

The natural gas supplied to our North Texas system is generally dedicated to us under individually negotiated contracts. Most of our contracts have an initial term of at least five years. Following the initial term, these contracts generally are renewed for additional terms or continue on a month-to-month or year-to-year basis unless terminated by us or the customer. As of May 1, 2013, the volume weighted-average remaining life of our North Texas system contracts is approximately 2.5 years. We gather and process natural gas under a combination of POP contracts, wellhead purchase/keep-whole contracts and fee-based contracts.

Recent Activity in the North Texas Basin. Within the last 12 months, the rig count in the North Texas basin has fluctuated between 34 and 68 active rigs, according to Rig Data. As of May 2013, our customers had four rigs drilling on acreage dedicated to us in the basin. Producers are pursuing wells with higher condensate and oil production relative to historical activity due to the relatively lower valued gas prospects. In 2011 and 2012, we added 46 and 89 new central receipt points directly connected to our North Texas system, respectively. During the first quarter of 2013 we added 17 new central receipt points to the North Texas system.

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Recent Growth Projects and Future Growth Opportunities. We recently installed a condensate stabilizer at our Springtown processing plant to enhance the value of condensate produced on our North Texas system assets. This condensate stabilizer enables our Springtown processing plant to stabilize over 4,000 Bpd of condensate for our logistics and marketing business and third parties. We have also recently completed an expansion to our North Texas system in Jack County, Texas to access the natural gas being produced in the area, and have entered into a processing agreement with a third party to enhance our processing capacity in this region.

Markets for Sale of Natural Gas, NGLs and Condensate. Our North Texas system has numerous market outlets for the natural gas that we gather and process and NGLs that we recover on our system. We have connections to major intrastate transportation pipelines that connect our facilities to market centers in the Dallas-Fort Worth area and ultimately to major market hubs in the U.S. Gulf Coast. The majority of our owned residue gas and all of our owned condensate and NGLs produced at our North Texas system processing plants is sold to our logistics and marketing business.

Texas Express NGL System

General. Our gathering, processing and transportation business also includes our 35% interest in the Texas Express NGL system, which consists of two separate joint ventures with third parties to design and construct a new NGL pipeline and NGL gathering system. The Texas Express NGL system mainline originates near Skellytown, Texas in the Texas Panhandle and, when completed, will extend approximately 580 miles to NGL fractionation and storage facilities in the Mont Belvieu area on the Texas Gulf Coast. The mainline is expected to have an initial capacity of approximately 280,000 Bpd and will be expandable to approximately 400,000 Bpd with the addition of intermediate pump stations on the system. There are currently capacity reservations on the mainline that, when fully phased in, will total approximately 250,000 Bpd. Based on existing capacity reservations, our logistics and marketing business will be a significant shipper on the system. The new NGL gathering system will initially consist of approximately 116 miles of gathering lines that will connect the mainline to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma and to Barnett Shale processing plants in North Texas. The gathering system is expected to include 270 miles of gathering lines by 2019. The joint venture that will own the mainline portion of the Texas Express NGL system is owned 35% by Enterprise Products Partners, 35% by us, 20% by Anadarko Petroleum Corporation and 10% by DCP Midstream. The joint venture that will own the new NGL gathering system is owned 45% by Enterprise Products Partners, 35% by us and 20% by Anadarko Petroleum Corporation. Enterprise Products Partners is constructing and will serve as the operator of the mainline, while we are constructing and will operate the new gathering system. The mainline and the initial portion of the gathering system are expected to begin service during the third quarter of 2013. We expect that the Texas Express NGL system 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. As of March 31, 2013, we have made contribution of approximately $216.4 million. We expect to contribute an additional $168.6 million in connection with the Texas Express NGL system.

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The following map identifies the locations of the principal assets comprising the Texas Express NGL system:

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NGL Supply. Volumes from the Rockies, Permian basin and Mid-Continent regions will be delivered to the Texas Express NGL system utilizing Enterprise Products Partners’ existing Mid-America Pipeline between the Conway hub and Enterprise Products Partners’ Hobbs NGL fractionation facility in West Texas. In addition, volumes from and to the Denver-Julesburg basin in Weld County, Colorado will be able to access the system upon the completion of the Front Range Pipeline by Enterprise Products Partners, DCP Midstream and Anadarko Petroleum Corporation, which is currently expected to occur during the fourth quarter of 2013.

Gathering, Processing and Transportation Customers

Our gathering, processing and transportation business serves customers predominantly in the Gulf Coast region of the United States and includes both upstream customers and purchasers of natural gas and NGLs. Upstream customers served by our systems primarily consist of small, medium and large independent operators and large integrated energy companies, while our demand market customers primarily consist of large users of natural gas, such as power plants, industrial facilities, local distribution companies and other large consumers. Due to the cost of making physical connections from the wellhead to gathering systems, the majority of our customers tend to renew their gathering and processing contracts with us rather than seeking alternative gathering and processing services. No customer accounted for more than 10% of our consolidated revenues for the fiscal years ended December 31, 2012, 2011 or 2010.

Gathering, Processing and Transportation Competitors

Competition for our gathering, processing and transportation business is significant in all of the markets we serve. Competitors include interstate and intrastate pipelines or their affiliates and other midstream businesses that gather, treat, process and market natural gas or NGLs. Our gathering business’ principal competitors are other midstream companies and, to a lesser extent, producer owned gathering systems. Some of these competitors are substantially larger than we are. Competition for the services we provide varies based upon the location of gathering, treating and processing facilities. Most upstream customers have alternate gathering, treating and processing facilities available to them. In addition, they have alternatives such as building their own gathering facilities or, in some cases, selling their natural gas supplies without treating and processing. In addition to location, competition also varies based upon pricing arrangements and reputation. On sour natural gas systems, such as parts of our East Texas system, competition is more limited in certain locations due to the infrastructure required to treat sour natural gas. Because pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipeline companies. Pipelines typically compete with each other based on location, capacity, price and reliability. Many of the large wholesale customers we serve have multiple pipelines connected or adjacent to their facilities. Accordingly, many of these customers have the ability to purchase natural gas directly from a number of pipelines or third parties that may hold capacity on the various pipelines. In addition, several new interstate natural gas pipelines have been and are being constructed in areas currently served by our natural gas transportation pipelines. Some of these new pipelines may compete for customers with our existing pipelines.

Logistics and Marketing

The primary role of our logistics and marketing business is to 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.

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The following table sets forth the volumes of natural gas, NGLs and crude oil sold by our logistics and marketing business for the time periods indicated:

Volumes of products sold	Three months ended March 31, 2013
Natural gas (MMBtu/day)		1,352,951
NGLs (Bpd)		164,108
Crude oil (Bpd)		29,693

Our services are provided using our owned or leased trucks, trailers and railcars; pipeline, fractionation and storage capacity; and product treating and handling equipment.

• Natural Gas Marketing. We market natural gas primarily at local market centers and major market hubs. To facilitate these marketing efforts, we utilize third-party transportation and storage contracts. As of March 31, 2013, we contracted for approximately 90,000 MMcf/d of firm transportation capacity and approximately 2.5 Bcf of firm natural gas storage capacity for periods beyond 2013. For the three months ended March 31, 2013, we sold approximately 1.4 Bcf/d of natural gas, of which 60% were volumes purchased from our gathering, processing and transportation business.

• NGL Marketing. We market NGLs in various ways, including at local market centers and major market hubs. To facilitate these marketing efforts, we utilize third party transportation, fractionation and storage contracts, as well as our owned or leased trucks, trailers and railcars. As of March 31, 2013, we contracted for approximately 115,000 Bpd of firm NGL fractionation and transportation capacity, 5.5 MMBbls of firm NGL storage capacity and used over 250 transport trucks, over 300 trailers and approximately 166 owned or leased railcars in support of our NGL marketing operations. For the three months ended March 31, 2013, we sold 164,108 Bpd of NGLs, of which 45% were volumes purchased from our gathering, processing and transportation business.

• Condensate and Crude Oil Marketing. We market condensate and crude oil primarily through direct sales to oil companies and refineries. To facilitate these marketing efforts, we utilize our TexPan railcar facility and an approximately 40-mile crude oil pipeline, crude oil barge loading facility and associated crude oil storage facility in Mississippi. These assets are complementary to our logistics and marketing business and provide us with access to more favorably priced crude oil markets. For the three months ended March 31, 2013, we sold 29,693 Bpd of condensate and crude oil, of which 30% were volumes purchased from our gathering, processing and transportation business.

Since major market hubs for natural gas and NGLs are located in the Mid-Continent and U.S. Gulf Coast regions of the United States and our logistics and marketing business assets are geographically located within Texas, Louisiana, Oklahoma and Mississippi, the majority of activities conducted by our logistics and marketing business are conducted within those states. However, our logistics and marketing assets, including our firm transportation capacity and firm natural gas storage capacity, are able to provide us and third parties with access to markets outside of the Mid-Continent and U.S. Gulf Coast regions in order to respond to market demand and to realize enhanced value from favorable pricing differentials. Additionally, our firm transportation capacity and our fleet of trucks, trailers and railcars mitigates the risk that our natural gas and NGLs will be shut in by capacity constraints on downstream NGL pipelines and other facilities.

Purchase and Resale Operations. One of the key components of our logistics and marketing business is our natural gas and NGL purchase and resale business. Through our natural gas and NGL purchase and resale operations, we can efficiently manage the transportation and delivery of natural gas and NGLs from our gathering, processing and transportation assets and deliver them through major natural gas transportation

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pipelines to industrial, utility and power plant customers, as well as to marketing companies at various market hubs throughout the Mid-Continent, Gulf Coast and Southeast regions of the United States. We typically price our sales based on a published daily or monthly price index. In addition, sales to wholesale customers include a pass-through charge for costs of transportation and additional margin to compensate us for the associated services we provide.

Storage, Transportation and Fractionation Contracts. We pay third-party storage facilities and pipelines for the right to store natural gas and NGLs for various periods of time under firm storage, interruptible storage or parking and lending services in order to mitigate risk associated with sales and purchase contracts. We also contract for third-party pipeline capacity under firm transportation contracts for which the pipeline capacity depends on volumes of natural gas from our natural gas assets. We contract this pipeline capacity for various lengths of time and at rates that allow us to diversify our customer base by expanding our service territory. We have also entered into multiple long-term fractionation contracts with third-party fractionators to provide access to fractionation capacity for our customers.

The following table sets forth additional detail regarding our significant third-party contracts under which we have reserved storage, transportation and fractionation capacity in support of the gathering, processing and transportation services we provide to our customers:

Commodity	Reserved Capacity	Expiration Year
Storage Contracts
Normal Butane	600,000 Bbls	2016
Multi-product NGL	500,000 Bbls	2014
Multi-product NGL	380,000 Bbls	2014
Multi-product NGL	350,000 Bbls	2014
Multi-product NGL	250,000 Bbls	2014
Propane	250 000 Bbls	2015
Natural Gas	1.8 Bcf	2016
Natural Gas	0.5 Bcf	2015
Natural Gas	0.2 Bcf(1)	2015
Transportation Contracts
Y-grade NGLs	29,000 to 120,000 Bpd(2)	2023
Y-grade NGLs	27,000 Bpd	2021
Natural Gas	7,000 to 20,000 MMcf/d(3)	2015
Natural Gas	7,000 to 20,000 MMcf/d(3)	2015
Natural Gas	10,000 MMcf/d	2014
Natural Gas	40,000 MMcf/d	2014
Fractionation Contracts
Y-grade NGLs	43,000 Bpd	2023
Y-grade NGLs	7,000 to 22,000 Bpd	2022
Y-grade NGLs	14,000 Bpd	2022

(1) Bundled with transportation contract.

(2) Represents our reserved capacity on NGL pipelines, including the Texas Express NGL mainline, which increases over the term of the contract.

(3) Reserved capacity varies by season.

Logistics and Marketing Customers

Our logistics and marketing business purchases and receives natural gas, NGLs and other products from our gathering, processing and transportation business as well as from third-party pipeline systems and processing plants and sells and delivers them to third-party customers. Most of the third-party customers of our logistics and marketing operations are wholesale customers, such as refiners and petrochemical producers, fractionators,

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propane distributors and industrial, utility and power plant customers. In addition, we sell natural gas and NGLs to marketing companies at various market hubs. No customer accounted for more than 10% of our consolidated revenues for the fiscal years ended December 31, 2012, 2011 or 2010.

Logistics and Marketing Competitors

Our logistics and marketing business has numerous competitors, including large natural gas and NGL marketing companies, marketing affiliates of pipelines, major oil, natural gas and NGL producers, other trucking, railcar and pipeline operations, independent aggregators and regional marketing companies. Our logistics and marketing business’ principal competitors include numerous natural gas and NGL marketing companies such as Energy Transfer Partners, Enterprise Products Partners, ONEOK, Targa Resources Partners and DCP Midstream and major integrated oil and natural gas companies.

Seasonality

Demand for our gathering, processing and transportation services primarily depends upon the supply of natural gas production and the drilling rate for new wells. The drilling activities of producers within our areas of operations generally do not vary materially by season but may be affected by adverse weather. Supply for our logistics and marketing operations depends to a large extent on the natural gas reserves and rate of drilling within the areas served by our gathering, processing and transportation business. Generally, the demand for natural gas and NGLs decreases during the spring and fall months and increases during the winter months and in some areas during the summer months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. Demand for natural gas with respect to power plant and utility customers is typically driven by weather-related factors.

Insurance

Our operations are subject to many hazards inherent in the midstream industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We expect to be insured under the comprehensive insurance program that is maintained by Enbridge for its subsidiaries, which we expect will include commercial liability insurance coverage that is consistent with coverage considered customary for our industry. The insurance coverage will include property insurance coverage on our assets, except pipeline assets that are not located at water crossings, including 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 insured Enbridge entities on an equitable basis based on an insurance allocation agreement we will enter into with Enbridge and other Enbridge subsidiaries. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Insurance Allocation Agreement.” We can make no assurance that the insurance coverage we maintain will be available or adequate for any particular risk or loss or that we will be able to maintain adequate insurance in the future at rates we consider reasonable. Although we believe that our assets are adequately covered by insurance, a substantial uninsured loss could have a material adverse effect on our financial position, results of operations and cash flows.

Focus on Safety and Integrity

We are committed to ensuring employee safety and the safety of the public through the safe operation of our assets. As part of our goal of zero incidents, we conduct business in a way that recognizes health and safety management as important components of our daily business. For our employees and contractors, we have enacted our “Health and Safety Principles” and our “Life Saving Rules” principles that outline our philosophy and approach to health and safety matters, as well as our expectations and employee obligations with respect to such matters. For the communities in which we operate we have a Public Awareness Program that provides information on how to dig

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safely, how to respond to a pipeline emergency, and how to contact us in an emergency. We also have a first responder education and training program that we make available at no cost to emergency responders in our areas of operation to enhance their ability to safely and effectively respond to a pipeline incident.

Pipeline Control Operations

Our pipeline systems are operated from a central control room located in Houston, Texas. The control center operates with a SCADA system equipped with computer systems designed to continuously monitor operational data. Monitored data includes but is not limited to pressures, flow rates and alarm conditions. The control center operates remote compressors and valves associated with the receipt and delivery of natural gas and other liquid hydrocarbons, and provides for the remote controlled shutdown of compressor stations on the pipeline system. A fully functional back-up operations center is also maintained and routinely operated throughout the year to ensure safe and reliable operations.

Rate and Other Regulation

Our transmission and gathering pipelines and related facilities, as well as our processing facilities and trucking and railcar operations are subject to extensive federal and state environmental, operational and safety regulation. The added costs imposed by regulations are generally no different than those imposed on our competitors. The failure to comply with such rules and regulations can result in substantial penalties and/or enforcement actions and added operational costs.

Intrastate Pipelines

Our transmission lines are subject to state regulation of rates and terms of service. In Texas, the regulatory system allows rates to be negotiated on a customer-by-customer basis and provides for a complaint-based review process. Our operations in Texas are generally subject to regulation under the Texas Utilities Code and the Texas Natural Resources Code, as implemented by the Texas Railroad Commission, or TRRC. The TRRC is vested with authority to ensure that the rates we negotiate with shippers for natural gas sales and transportation services are just and reasonable. Unless challenged in a complaint, such rates are deemed just and reasonable under Texas law. The Texas Utility Code and the Texas Natural Resources Code provide for a formal and an informal complaint process that is conducted by the TRRC. In rare circumstances, as allowed by statute, regulators may initiate a rate review. In Oklahoma, our operations are subject to primary regulation by the Oklahoma Corporation Commission. Oklahoma has a non-discriminatory access requirement, which is subject to a complaint-based review. In Louisiana, our propylene line is subject to the regulatory oversight of the Louisiana Public Service Commission and the Louisiana Office of Conservation.

Section 311 Pipelines

Intrastate transportation of natural gas is largely regulated by the state in which such transportation takes place. Several of our intrastate pipeline subsidiaries, Enbridge Pipelines (East Texas) L.P., Enbridge Pipelines (North Texas) L.P., and Enbridge Pipelines (Oklahoma Transmission) L.L.C., also provide interstate transportation service. The rates, terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act, or NGPA, and Part 284 of the FERC’s regulations. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline or a local distribution company, or LDC, served by an interstate natural gas pipeline. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The rates under Section 311 approved by the FERC are maximum rates and we may negotiate contractual rates at or below such maximum rates. Currently, the FERC reviews our maximum rates every five years and such maximum rates may increase or decrease as a result of such reviews. Should the FERC determine not to authorize rates equal to or greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to transportation service under Section 311, failure to comply with the rates

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approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in alteration of jurisdictional status, and/or the imposition of administrative, civil and criminal remedies or sanctions.

Gathering Pipeline Regulation

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. Although the FERC has not made formal determinations with respect to all of our facilities, we believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. 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 service in excess of the rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our natural gas gathering operations are subject to ratable take and common purchaser statutes in the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. States in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to these regulations.

NGL Pipeline Regulation

Both the mainline portion and the gathering line portion of the Texas Express NGL system will be a common carrier of NGLs subject to regulation by various federal agencies and the TRRC. The FERC regulates interstate pipeline transportation of crude oil, petroleum products and other liquids, such as NGLs (collectively, “petroleum pipelines”), under the Interstate Commerce Act, or the ICA, and the Energy Policy Act of 1992, or EPAct 1992, and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on petroleum pipelines be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. In accordance with FERC regulations, transportation rates and terms and conditions of service will be filed with the FERC upon completion of each of the mainline portion and gathering line portion of the system. Under the ICA, interested persons may challenge new or changed rates or services. The FERC is authorized to investigate such charges and may suspend the effectiveness of a challenged rate for up to seven months. A successful rate challenge could result in a petroleum pipeline paying refunds together with interest for the period that the rate was in effect. The FERC may also investigate, upon complaint or on its own motion, existing rates and related rules and may order a pipeline to change them prospectively. A shipper may obtain reparations for damages sustained for a period up to two years prior to the filing of a complaint.

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EPAct 1992 required the FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, the FERC adopted an indexed rate methodology, which, as currently in effect, allows interstate petroleum pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI, as provided by the U.S. Department of Labor, Bureau of Labor Statistics. The FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 2.65%. The indexing methodology is applicable to existing rates with the exclusion of market-based rates. A pipeline is not required to raise its rates up to the index ceiling, but is permitted to do so, and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling.

If our rate levels were investigated by FERC on its own initiative or in response to a protest or complaint filed by an interested person, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of costs, including the overall cost of service, including operating costs and overhead; the allocation of overhead and other administrative and general expenses to the regulated entity; the appropriate capital structure to be utilized in calculating rates; the appropriate rate of return on equity and interest rates on debt; the rate base, including the proper starting rate base; the throughput underlying the rate; and the proper allowance for federal and state income taxes.

Two of our NGL pipelines in Texas, which do not provide service to third parties, operate under temporary waivers from the filing and reporting requirements of Sections 6 and 20 of the ICA. The waivers are effective until a third-party shipper requests service. In addition, certain of our NGL pipelines are regulated as a common carrier by the TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates we charge for NGL transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, our business may be adversely affected. The TRRC requires that intrastate NGL pipelines file tariff publications that contain all the rules and regulations governing the rates and charges for service performed. The applicable Texas statutes require that NGL pipeline rates provide no more than a fair return on the aggregate value of the pipeline property used to render services. State commissions have generally not been aggressive in regulating common carrier pipelines and have generally not investigated the rates or practices of NGL pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved informally. Although we cannot assure you that our intrastate rates would ultimately be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

Market Behavior Rules; Posting and Reporting Requirements

On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or the EPAct 2005. Among other matters, the EPAct 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the anti-manipulation provision of the EPAct 2005. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC or the purchase or sale of transportation services subject to the jurisdiction of the FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.

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The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering to the extent such transactions do not have a “nexus” to jurisdictional transactions. The EPAct 2005 also amends the NGA and the NGPA to give the FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules, and orders, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, the FERC issued a revised policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines. In addition, the Commodities Futures Trading Commission, or the CFTC, is directed under the Commodities Exchange Act, or the CEA, to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of one million dollars ($1,000,000) or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.

The EPAct of 2005 also added a Section 23 to the NGA authorizing the FERC to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce. In 2007, the FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Order No. 704 requires buyers and sellers of annual quantities of natural gas of 2,200,000 MMBtu or more, including entities not otherwise subject to the FERC’s jurisdiction, to provide by May 1 of each year an annual report to the FERC describing their aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with the FERC’s policy statement on price reporting. In June 2010, the FERC issued the last of its three orders on rehearing and clarification further clarifying its requirements.

In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating under Section 1(c) of the NGA to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on the FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. Order No. 735 became effective on April 1, 2011. In December 2010, the Commission issued Order No. 735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring Section 311 and “Hinshaw” pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract. In June 2011, the Commission extended the time for filing form 549D, the subject of Order No. 735, for the first quarter of 2011 until September 9, 2011, and for the second quarter until September 30, 2011.

In October 2010, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether and how parties that hold firm capacity on some intrastate pipelines can allow others to use their capacity, including to what extent buy/sell transactions should be permitted and whether the FERC should consider requiring such

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pipelines to offer capacity release programs. In the Notice of Inquiry, the FERC granted a blanket waiver regarding such transactions while the FERC is considering these policy issues. The comment period has ended but the FERC has not yet issued an order. At this time, we do not expect any additional action by the FERC.

On November 15, 2012, the FERC issued a Notice of Inquiry seeking public comment on the issue of whether to amend its regulations under the natural gas market transparency provisions of Section 23 of the NGA, as adopted by EPAct 2005, to consider the extent to which quarterly reporting of every natural gas transaction within the FERC’s NGA jurisdiction that entails physical delivery for the next day or next month would provide useful information for improving natural gas market transparency. The comment period has ended, but the FERC has not yet issued an order.

Sales of Natural Gas, Condensate and NGLs

The price at which we sell natural gas currently is not subject to federal or state regulation except for certain systems in Texas. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and to facilitate price transparency in markets for the wholesale sale of physical natural gas.

Our sales of condensate and NGLs currently are not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC’s jurisdiction under the ICA. Certain regulations implemented by the FERC in recent years could increase the cost of transportation service on certain products pipelines. However, we do not believe that these regulations affect us any differently than other marketers of these products.

Pipeline Safety and Transportation Regulation

Some of our gas pipelines are subject to regulation by the PHMSA pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002, or PSIA, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas, or HCAs. Our NGL pipelines, our crude oil pipeline and our propylene pipeline are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979, or the HLPSA, which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline, and the Pipeline Safety Act of 1992, or the PSA, which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act of 1996, or the APSA, which limited the operator identification requirement to operators of pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management.

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The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including us, to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a HCA;

• improve data collection, integration and analysis;

• repair and remediate pipelines as necessary; and

• implement preventive and mitigating actions.

Although many of our pipeline facilities fall within a class that is currently not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our non-exempt pipelines, particularly our North Texas system. We currently estimate that we will incur approximately $3.2 million during 2013 to complete the testing required by existing DOT regulations and their state counterparts. This estimate does not include the costs for any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that we expand our integrity management program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on our operations.

Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. On August 13, 2012, PHMSA published a proposed rulemaking consistent with the signed act that, once finalized, will increase the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. The PHMSA recently issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. The PHMSA has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrotests of our facilities to confirm the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines

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installed before 1970. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

We have incorporated all existing requirements into our programs by the required regulatory deadlines, and are continually incorporating the new requirements into procedures and budgets. We expect to incur increasing regulatory compliance costs, based on the intensification of the regulatory environment and upcoming changes to regulations as outlined above. In addition to regulatory changes, costs may be incurred when there is an accidental release of a commodity transported by our system, or a regulatory inspection identifies a deficiency in our required programs.

When hydrocarbons are released into the environment or violations identified during an inspection, PHMSA may issue a civil penalty or enforcement action, which can require internal inspections, pipeline pressure reductions and other methods to manage or verify the integrity of a pipeline in the affected area. In addition, the National Transportation Safety Board may perform an investigation of a significant accident to determine the probable cause and issue safety recommendations to prevent future accidents.

We believe that our pipeline, trucking and railcar operations are in substantial compliance with applicable operational and safety requirements. In instances of non-compliance, we have taken actions to remediate the situations. Nevertheless, significant operating expenses and capital expenditure could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the capabilities of our current pipeline control system or other safety equipment.

Environmental Regulation

General

Our operations are subject to complex federal, state and local laws and regulations relating to the protection of health and the environment, including laws and regulations that govern the handling, storage and release of liquid hydrocarbon materials or emissions from natural gas compression facilities. As with the pipeline and processing industry in general, complying with current and anticipated environmental laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position since the operations of our competitors are generally similarly affected.

In addition to compliance costs, violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. We believe that our operations are in substantial compliance with applicable environmental laws and regulations.

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There are also risks of accidental releases into the environment associated with our operations, such as releases or spills of liquid hydrocarbon materials, natural gas or other substances from our pipelines or storage facilities. Such accidental releases could, to the extent not insured, subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines, penalties or damages for related violations of environmental laws or regulations.

Air and Water Emissions

Our operations are subject to the CAA and the CWA, and comparable state and local statutes. We anticipate, therefore, that we will incur costs in the next several years for air pollution control equipment and spill prevention measures in connection with maintaining existing facilities and obtaining permits and approvals for any new or acquired facilities. On October 7, 2010, the EPA extended the compliance date for the Spill Prevention, Control, and Countermeasures Rule Amendments to November 10, 2011. As the operations of our pipeline facilities are subject to the rule, we prepared the necessary plans for compliance prior to the November 2011 effective date, as the EPA had originally set November 10, 2010 as the compliance date. In 2009, the EPA published the Greenhouse Gas Recordkeeping and Reporting Rule, which requires covered facilities to record and report greenhouse gas emissions from combustion sources beginning January 1, 2010. As a part of the reporting rule, in November 2010, the EPA published the requirements for reporting emissions from Petroleum and Natural Gas Systems beginning January 1, 2011. While the operations of our pipelines are subject to the rule, we do not believe that the rule requirements will have a material effect on our operations. Annual emissions from combustion activities in 2010 were reported prior to the September 30, 2011 deadline. Facilities subject to existing Greenhouse Gas Reporting rules reported emissions prior to the March 31, 2012 deadline for 2011 emissions. Facilities subject to the new reporting rules in 2011 reported emissions prior to the September 28, 2012 deadline. On August 23, 2011, the EPA proposed New Source Performance Standards, or the NSPS, Subpart OOOO, for volatile organic compounds, or VOCs, and sulfur dioxide, or SO2, emissions from the oil and natural gas sector. The final standards were published and became effective on August 16, 2012. The compliance dates range from October 15, 2012, to October 15, 2013, depending on the affected equipment. On April 12, 2013, the EPA proposed amendments to NSPS, Subpart OOOO, that would, among other things, provide additional time for recently constructed, modified or reconstructed storage vessels to install VOC controls. There will be additional costs across the industry to attain compliance with NSPS Subpart OOOO, but we do not expect a material effect on our financial statements.

The Oil Pollution Act, or OPA, was enacted in 1990 and amends parts of the CWA and other statutes as they pertain to the prevention of and response to oil spills. Under the OPA, we could be subject to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill from our facilities into navigable waters, along shorelines or in an exclusive economic zone of the United States. The OPA also imposes certain spill prevention, control and countermeasure requirements for many of our non-pipeline facilities, such as the preparation of detailed oil spill emergency response plans and the construction of dikes or other containment structures to prevent contamination of navigable or other waters in the event of an oil overflow, rupture or release. For our liquid pipeline facilities, the OPA imposes requirements for emergency plans to be prepared, submitted and approved by the DOT. We believe that we are in material compliance with these laws and regulations.

Hazardous Substances and Waste Management

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA (also known as the “Superfund” law) and similar state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons, including the owners or operators of waste disposal sites and companies that disposed or arranged for disposal of hazardous substances found at such sites. We may generate some wastes that fall within the definition of a “hazardous substance.” We may, therefore, be jointly and severally liable under CERCLA for all or part of any costs required to clean up and restore sites at which such

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wastes have been disposed of, as well as natural resource damages. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws may apply to a broader range of substances than CERCLA and, in some instances, may offer fewer exemptions from liability. We have not received any notification that we may be potentially responsible for material cleanup costs or natural resource damages under CERCLA or similar state laws.

Site Remediation

We own and operate a number of pipelines, gathering systems, storage facilities and processing facilities that have been used to transport, distribute, store and process crude oil, natural gas and other petroleum products. Many of our facilities were previously owned and operated by third parties whose handling, disposal and release of petroleum and waste materials were not under our control. The age of the facilities, combined with the past operating and waste disposal practices, which were standard for the industry and regulatory regime at the time, have resulted in soil and groundwater contamination at some facilities due to historical spills and releases. Such contamination is not unusual within the natural gas and petroleum industry. Historical contamination found on, under or originating from our properties may be subject to CERCLA, OPA, the Resource Conservation & Recovery Act and analogous state laws as described above.

Under these laws, we could incur substantial expense to remediate such contamination, including contamination caused by prior owners and operators. We have conducted site investigations at some of our facilities to assess historical environmental issues, and we are currently addressing soil and groundwater contamination at various facilities through remediation and monitoring programs, with oversight by the applicable governmental agencies where appropriate. However, we do not believe any of these remediation or monitoring expenses will be material.

Employee Safety

We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state, and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Endangered Species Act

The Endangered Species Act restricts activities that may affect endangered species or their habitats. While some of our facilities are in areas that may be designated as habitat for endangered species, we believe that we are in substantial compliance with the Endangered Species Act. However, the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.

Hazardous Materials Transportation Requirements

The DOT regulations affecting pipeline safety require pipeline operators to implement measures designed to reduce the environmental impact of crude oil and product discharge from onshore crude oil and product pipelines. These regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. In addition, the DOT regulations contain detailed specifications for pipeline operation and maintenance. We believe our operations are in compliance with these regulations. The DOT also has a pipeline integrity management rule, with which we are in substantial compliance.

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Anti-terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. Currently, none of our facilities have been determined by DHS to pose a high level of security risk.

While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered in the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. We are currently implementing our own cyber-security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

Title to Properties and Permits

Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines. Some of our permits may continue to be held by affiliates of EEP until we have made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. We will make these filings and obtain these consents upon completion of this offering.

Employees

We are managed and operated by the board of directors and executive officers of Midcoast Holdings, L.L.C., our general partner. Neither we nor our subsidiaries have any employees. Our general partner is responsible for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of EEP’s general partner. Immediately after the closing of this offering, we expect that our general partner and its affiliates will have approximately 1,250 employees performing services for our operations. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.

Legal Proceedings

We are a participant in a number of legal proceedings arising in the ordinary course of business. Some of these proceedings are not covered, in whole or in part, by insurance. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial position, results of operations or cash flows. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

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MANAGEMENT

Management of Midcoast Energy Partners, L.P.

We are managed by the directors and executive officers of our general partner, Midcoast Holdings, L.L.C. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. EEP indirectly owns all of the membership interests in our general partner. Through a delegation of control agreement, EEP’s general partner has delegated to 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. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or directly or indirectly to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Following the closing of this offering, we expect that our general partner will have at least four directors. EEP will appoint all members to the board of directors of our general partner. In accordance with the NYSE’s phase-in rules, we will have at least one independent director on the date that our common units are first listed on the NYSE and three independent directors within one year of that date.

Neither we nor our subsidiaries have any employees. Our general partner is responsible for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of EEP’s general partner, but we sometimes refer to these individuals in this prospectus as our employees.

Director Independence

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

Committees of the Board of Directors

The board of directors of our general partner will have an audit, finance and risk committee and a conflicts committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit, Finance and Risk Committee

At least three independent members of the board of directors of our general partner will serve as members of our audit, finance and risk committee, which will exercise the functions of an audit committee under the rules of the SEC and NYSE. Our general partner initially may rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit, finance and risk committee. Those rules permit our general partner to have an audit committee that has one independent member by the date our common units are first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. Our audit, finance and risk committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and

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corporate policies and controls. Our audit, finance and risk committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit, finance and risk committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit, finance and risk committee.

Conflicts Committee

At least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. Our conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our incentive compensation plan. If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”

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

Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of Midcoast Holdings, L.L.C.

Name	Age		Position with Midcoast Holdings, L.L.C.
Mark A. Maki		48	President and Director
Terrance L. McGill		58	Chief Operating Officer and Director
Janet L. Coy		55	Vice President—Natural Gas Marketing
E. Chris Kaitson		56	Vice President—Law and Assistant Secretary
John A. Loiacono		50	Vice President—Commercial Activities
Byron C. Neiles		47	Vice President—Major Projects
Stephen J. Neyland		45	Vice President—Finance
Kerry C. Puckett		51	Vice President—Engineering and Operations, Gathering & Processing
William M. Ramos		53	Controller
Allan M. Schneider		54	Vice President—Regulated Engineering and Operations
Bruce A. Stevenson		57	Corporate Secretary
Darren Yaworsky		42	Treasurer

Mark A. Maki

Mark A. Maki was appointed President and elected as a director of our general partner in May 2013. Mr. Maki will split his professional time among his roles at EEP’s general partner, Enbridge Management, Enbridge and our business. Mr. Maki has served as President of Enbridge Management and Senior Vice President of EEP’s general partner since October 2010 and was elected as a director of both companies at that time. Mr. Maki previously served as Vice President—Finance of EEP’s general partner and Enbridge

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Management from July 2002 to October 2010. Prior to that time, Mr. Maki served as Controller of EEP’s general partner and Enbridge Management from June 2001 to July 2002 and as Controller of Enbridge Pipelines Inc. from September 1999 to June 2001.

Mr. Maki progressed through a series of accounting and financial roles of increasing responsibility during his 26 years with Enbridge in the United States and Canada. Through his broad range of domestic and Canadian experience in the pipeline industry, Mr. Maki provides our board with financial expertise, leadership skills in our industry and knowledge of our local community and business environment.

Terrance L. McGill

Terrance L. McGill was elected as a director and appointed Chief Operating Officer of our general partner in May 2013. Mr. McGill will split his professional time among his roles at EEP’s general partner, Enbridge Management, Enbridge and our business. Mr. McGill has served as President of EEP’s general partner and Senior Vice President of Enbridge Management since October 2010. Prior to October 2010, Mr. McGill had served as a director and President of EEP’s general partner and Enbridge Management since May 2006. Mr. McGill previously served as Vice President—Commercial Activity and Business Development of EEP’s general partner and Enbridge Management from April 2002 and Chief Operating Officer from July 2004. Prior to that time, Mr. McGill was President of Columbia Gulf Transmission Company from January 1996 to March 2002.

As a director and Chief Operating Officer of our general partner, Mr. McGill gives our board insight and in-depth knowledge of our industry and our specific operations and strategies. He also provides leadership skills, pipeline operations and management expertise and knowledge of our local community and business environment, which he has gained through his long career in the oil and gas industry.

Other Officers

Janet L. Coy was appointed Vice President—Natural Gas Marketing of our general partner in May 2013. Ms. Coy will devote substantially all of her professional time to our business and affairs. Ms. Coy has served as Vice President—Natural Gas Marketing of EEP’s general partner and Enbridge Management since October 2010. Ms. Coy previously served as President of the Natural Gas Marketing subsidiaries of EEP’s general partner and Enbridge Management since the acquisition of Midcoast Energy Resources, Inc. and continues to serve in that capacity.

E. Chris Kaitson was appointed Vice President—Law and Assistant Secretary of our general partner in May 2013. Mr. Kaitson will split his professional time among his roles at EEP’s general partner, Enbridge Management, Enbridge and our business. Mr. Kaitson has served as Vice President—Law and Assistant Secretary of EEP’s general partner and Enbridge Management since May 2007. He also currently serves as Deputy General Counsel of Enbridge. Prior to that, he was Assistant General Counsel and Assistant Secretary of EEP’s general partner and Enbridge Management from July 2004 to May 2007. He served as Corporate Secretary of EEP’s general partner from October 2001 to July 2004 and as Corporate Secretary of Enbridge Management from May 2002 to July 2004. He was previously Assistant Corporate Secretary and General Counsel of Midcoast Energy Resources, Inc. from 1997 until it was acquired by Enbridge in May 2001.

John A. Loiacono was appointed Vice President—Commercial Activities of our general partner in May 2013. Mr. Loiacono will devote substantially all of his professional time to our business and affairs. Mr. Loiacono has served as Vice President—Commercial Activities of EEP’s general partner and Enbridge Management since July 2006. Prior to that, he was Director of Commercial Activities for EEP’s general partner and Enbridge Management from April 2003 to July 2006 and commenced employment with Midcoast Energy Resources, Inc. in February 2000 as an Asset Optimizer until it was acquired by Enbridge in May 2001.

Byron C. Neiles was appointed Vice President—Major Projects of our general partner in May 2013. Mr. Neiles will devote the majority of his professional time to his roles at Enbridge, Enbridge Management and

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EEP’s general partner, and will also spend time, as needed, devoted to our business and affairs. Mr. Neiles has served as Vice President—Major Projects of EEP’s general partner and Enbridge Management since October 2010. Mr. Neiles was named Senior Vice President—Major Projects of Enbridge in November 2011 and had previously served Enbridge as Vice President in the Major Projects division since April 2008, prior to which he was Vice President of Enbridge Gas Distribution from 2003 to 2008. Mr. Neiles joined Enbridge in 1994.

Stephen J. Neyland was appointed Vice President—Finance of our general partner in May 2013. Mr. Neyland will split his professional time among his roles at EEP’s general partner, Enbridge Management and our business, and will also spend time, as needed, on behalf of Enbridge. Mr. Neyland has served as Vice President—Finance of EEP’s general partner and Enbridge Management since October 2010. Mr. Neyland was previously Controller of EEP’s general partner and Enbridge Management from September 2006 to October 2010. Prior to September 2006, he had served as Controller—Natural Gas since January 2005, Assistant Controller from May 2004 to January 2005 and in other managerial roles in finance and accounting from December 2001 to May 2004. Prior to that time, Mr. Neyland was Controller of Koch Midstream Services from 1999 to 2001.

Kerry C. Puckett was appointed Vice President—Engineering and Operations, Gathering & Processing of our general partner in May 2013. Mr. Puckett will devote substantially all of his professional time to our business and affairs. Mr. Puckett has served as Vice President—Engineering and Operations, Gathering & Processing of EEP’s general partner and Enbridge Management since October 2007. Prior to his appointment, he served as General Manager of Engineering and Operations from 2004 to 2007 and Manager of Operations from 2002 to 2004. Prior to that time, he served as Manager of Business Development for Sid Richardson Energy Services Company.

William M. Ramos was appointed Controller of our general partner in May 2013. Mr. Ramos will split his professional time among his roles at EEP’s general partner, Enbridge Management and our business, and will also spend time, as needed, on behalf of Enbridge. Mr. Ramos has served as Controller of EEP’s general partner and Enbridge Management since October 2010. Prior to his appointment, he served as Assistant Controller and in other managerial roles of EEP’s general partner with responsibility for financial accounting, reporting and control from April 2005 to October 2010. Mr. Ramos served in various management capacities in energy-related companies prior to 2005.

Allan M. Schneider was appointed Vice President—Regulated Engineering and Operations of our general partner in May 2013. Mr. Schneider will split his professional time among his roles at EEP’s general partner, Enbridge Management, Enbridge and our business. Mr. Schneider has served as Vice President—Regulated Engineering and Operations of EEP’s general partner and Enbridge Management since October 2007. Prior to his appointment, he served as Director of Engineering and Operations for Regulated & Offshore and Director of Engineering Services from January 2005 to October 2007. Mr. Schneider was Vice President of Engineering and Operations for Shell Gas Transmission, L.L.C. from December 2000 to January 2005.

Bruce A. Stevenson was appointed Corporate Secretary of our general partner in May 2013. Mr. Stevenson will split his professional time among his roles at EEP’s general partner, Enbridge Management and our business. Mr. Stevenson has served as Corporate Secretary of EEP’s general partner and Enbridge Management since July 2004. Between 2000 and 2004, Mr. Stevenson held management positions with Reliant Energy, Inc. and Arthur Andersen LLP. Prior to that Mr. Stevenson was General Counsel & Corporate Secretary of Alberta Natural Gas Company Ltd, a Canadian gas processing and transmission company that was acquired by TransCanada Pipelines.

Darren J. Yaworsky was appointed Treasurer of our general partner in May 2013. Mr. Yaworsky will split his professional time among his roles at EEP’s general partner, Enbridge Management and our business, and will also spend time on Enbridge matters and affairs. Mr. Yaworsky has served as Treasurer of EEP’s general partner and Enbridge Management since October 2012. He is also Director—Treasury, for Enbridge, a position he has held since March 2011. Mr. Yaworsky has held the following positions since joining Enbridge in February 2008: From 2010 to 2011, he served as Senior Manager—Treasury and from 2008 to 2010 he was Manager—Treasury. Prior to joining Enbridge, Mr. Yaworsky was Managing Director with Bank of Montreal from 2005 to 2008 and has worked in the banking industry since 1998.

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Board Leadership Structure

While the board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer, it has been the practice of Enbridge companies to separate the roles. We expect that EEP will elect a non-executive chairman to the board of directors of our general partner at a future date. Current directors of the board of directors of our general partner are designated or elected by EEP. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Board Role in Risk Oversight

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit, finance and risk committee, which is responsible for reviewing and discussing with management and our registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

Compensation of Our Officers and Directors

General

We are a master limited partnership and do not employ directly any employees, nor do we have executive officers or directors. We are managed by our general partner, and the named executive officers, or NEOs, are executive officers of our general partner. Our general partner is wholly owned and controlled by EEP, which is also a master limited partnership and does not directly employ any employees. Our general partner has entered into an intercorporate services agreement with EEP, which is managed and controlled by Enbridge Management, to provide us with managerial, administrative and operational services. EEP’s general partner, Enbridge Management and Enbridge, through its affiliates, provide managerial, administrative, operational and director services to EEP pursuant to service agreements among them and EEP. Pursuant to our intercorporate services agreement, we will reimburse our general partner and EEP for an allocated portion of the costs of these services, which costs include a portion of the compensation of the NEOs. For additional information regarding the intercorporate services agreement, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Intercorporate Services Agreement.”

Since neither we nor EEP have any direct employees, and our general partner and EEP do not have responsibility for approving the elements of compensation for the NEOs, we, our general partner and EEP do not have compensation policies. The compensation policies and philosophy of Enbridge govern the types and amounts of compensation of each of the NEOs. The NEOs are:

• Mark A. Maki, President and Director (our principal executive officer);

• Terrance L. McGill, Chief Operating Officer and Director;

• Stephen J. Neyland, Vice President—Finance (our principal financial officer);

•                     ; and

•                      .

Messrs. Maki, McGill and Neyland are also executive officers of EEP’s general partner and Enbridge Management. Compensation of our NEOs is determined as part of an Enbridge enterprise-wide review process.

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Each business unit develops a salary increase budget recommendation, in consultation with the Enbridge corporate compensation department, based on a competitive analysis of the labor market for that business unit. These recommendations are presented, in summary and on a business unit basis, to the Human Resources and Compensation Committee of the board of directors of Enbridge, or the HRC Committee, for approval. Individual salary increases are implemented after the HRC Committee approves the overall budget. Compensation adjustments for senior leadership of the various business units are recommended by their supervisors and reviewed by the executive leadership team of Enbridge in the aggregate before being recommended to the HRC Committee. The Enbridge executive leadership team, the President & Chief Executive Officer of Enbridge and the HRC Committee do not review the elements of compensation for Messrs. Maki, McGill and Neyland on an individual basis. A member of the Enbridge executive leadership team makes compensation recommendations for Messrs. Maki, McGill and Neyland, which are subject to the Enbridge enterprise-wide review process described above. Enbridge’s President & Chief Executive Officer approves the aggregate of all individual salary increase recommendations, on an enterprise-wide basis, to ensure that compensation expense is within the budget approved by the HRC Committee. Each of the NEOs provides services to other affiliates of Enbridge and, therefore, his compensation is determined on the basis of his overall performance with respect to Enbridge and all of its affiliates and not solely based on his performance with respect to us or EEP.

We are a partnership and not a corporation for United States federal income tax purposes, and therefore, are not subject to the executive compensation tax deductible limitations of Internal Revenue Code §162(m). In addition, we are not the employer for any of the NEOs.

For a more detailed discussion of the compensation policies and philosophy of Enbridge, we refer you to a discussion of those items as set forth in the Executive Compensation section of the Enbridge Management Information Circular, or MIC, on the Enbridge website at www.enbridge.com. The Enbridge MIC is produced by Enbridge pursuant to Canadian securities regulations and is not incorporated into this document by reference. We refer to the MIC to provide our investors with an understanding of the compensation policies and philosophy of the ultimate parent of our general partner.

Elements of Compensation

The HRC Committee sets the compensation philosophy of Enbridge, which is approved by the Enbridge board of directors. Enbridge has a pay-for-performance philosophy and programs that are designed to be aligned with its interests, on an enterprise-wide basis, as well as the interests of its shareholders. A significant portion of total direct compensation of Enbridge’s senior management is dependent on actual performance measured against short, medium and long-term performance goals of Enbridge, on an enterprise-wide basis, which are approved by the Enbridge board of directors. As a business unit of Enbridge, we and EEP will contribute to its overall growth, earnings and attainment of performance goals.

The elements of total compensation in 2012 for Messrs. Maki, McGill, Neyland,          and          are:

• Base Salary—to provide a fixed level of compensation for performing day-to-day responsibilities, while balancing the individual’s role and competency, market conditions and issues of attraction and retention.

• Short-term incentive—to provide a competitive, performance-based cash award based on pre-determined corporate, business unit and individual goals that measure the execution of the business strategy over a one-year period.

• Medium-term and long-term incentives—to recognize contributions and provide competitive, performance-based compensation comprised of performance stock units and incentive stock options that are tied to the share price of Enbridge common shares, and are mostly at-risk to motivate performance over the medium and long term.

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• Pension plan—to provide a competitive retirement benefit.

• Savings plan—to promote ownership of Enbridge common shares and to provide the opportunity to save additional funds for retirement or other financial goals.

• Perquisites—to provide a competitive allowance to offset expenses largely related to the executive’s role.

• Benefits—to provide security pertaining to health and welfare risks in a flexible manner to meet individual needs.

The HRC Committee makes determinations as to whether the enterprise-wide performance goals have been achieved, approves business unit results and if adjustments are necessary to more accurately reflect whether those goals have been met or exceeded. For example, the HRC Committee may determine to disregard a non-cash gain or loss reflected in our results of operations that resulted from mark-to-market accounting for our derivative activities in determining whether certain goals have been met.

Base Salary

Base salary for the NEOs reflects a balance of market conditions, role, individual competency and attraction and retention considerations and takes into account compensation practices at peer companies of Enbridge. Increases in base pay for all NEOs are based primarily on competitive considerations.

Short-Term Incentive Plan

The Enbridge short-term incentive plan, or STIP, is designed to provide incentive for, and reward the achievement of goals that are aligned with the Enbridge annual business plan. The target short-term incentive reflects the level of responsibility associated with the role and competitive practice and is expressed as a percentage of base salary. Actual incentive awards can range from zero to two times the target. Awards under the plan are based on performance relative to goals achieved at the Enbridge corporate level, business unit level and individual level. Performance relative to goals in each of these areas is reflected on a scale of zero to two; zero indicates performance was below threshold levels, one indicates that goals were achieved and two indicates that performance was exceptional. Enbridge corporate performance is a factor in determining incentive awards.

The following is a summary for 2012 of the incentive targets, payout range, and relative weightings between the Enbridge corporate, business unit and individual performance:

							Relative Weighting
	Target STIP%(1)			Pay Out Range			Corporate			Business Unit			Individual
Mark A. Maki		40	%		0-80	%		25	%		50	%		25	%
President and Director
Terrance L. McGill		40	%		0-80	%		25	%		50	%		25	%
Chief Operating Officer and Director
Stephen J. Neyland		35	%		0-70	%		25	%		50	%		25	%
Vice President—Finance

(1) All values are expressed as percentages of base salary.

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The overall performance multiplier and STIP are calculated as follows:

Performance multiplier	STIP
Corporate target incentive opportunity x (0-2)	Base Salary $
+   Business unit target incentive opportunity x (0-2)	x   Target STIP %
+   Individual target incentive opportunity x (0-2)	x   Overall performance multiplier (0-2)
=   Overall performance multiplier (0-2)	=   $ Short term incentive award

Enbridge Corporate Performance

Corporate performance is measured by adjusted earnings per share, or EPS. This is a metric that focuses on return to shareholders and is aligned with how investors and security analysts assess Enbridge’s performance on an annual basis.

The adjusted EPS metric represents a significant component of Enbridge’s corporate named executives’ short-term incentive award at 25% for all NEOs. Enbridge’s 2012 EPS guidance range was $1.58 Canadian Dollars (“CAD”) to $1.74 CAD as approved by the Enbridge Board prior to the start of 2012. Actual performance was $1.62 CAD. Adjustments are made to ensure the result is a fair reflection of performance. Approximately $639 million CAD of losses were adjusted out of the calculation, including mark to market losses and losses from asset impairment. The corporate multiplier ranges from 0 to 2.0, with 1.0 meaning that the performance measure was met.

During 2012, Enbridge management undertook, with the approval of the Enbridge board of directors, a supplementary financing plan that included $2.8 billion CAD of common equity, preferred equity and debt pre-funding actions that were not provided for in the original budget, prompted by the significant expansions to the Enbridge five-year growth capital plan, which emerged over the course of the year. Although these actions had an adverse impact on 2012 Enbridge’s EPS, they were necessary and prudent steps to support the medium and long-term objectives of Enbridge. The HRC Committee approved an adjustment to the calculated EPS result utilized for the corporate performance multiplier for short-term incentive purposes only, to better align the short-incentive awards for employees with the positive near-term and long-term outcomes for shareholders and Enbridge. Adjusting out the impact of the specific pre-funding actions noted above resulted in an adjusted EPS of $1.676 CAD (versus $1.62 CAD per share) and a short-term corporate multiplier of 1.20 out of 2.0.

Enbridge Business Unit Performance

Business unit performance measures vary among the NEOs to reflect the annual business plans and operations for which each NEO is accountable. Performance is measured against targets that are established at the beginning of the year. The detailed business unit performance measures for each of the NEOs are set forth in the tables which follow.

The business performance measure for each NEO is designed to reflect their multiple responsibilities at Enbridge. For 2012, Mr. Maki’s performance measure is calculated at 50% for the Gas Transportation business unit and 50% for the Shared Services business unit, resulting in a business unit multiplier of 1.04 out of 2.0. For 2012, Mr. McGill’s performance measure is calculated at 75% for the Gas Transportation business unit and 25% for the Gas Development business unit, resulting in a business unit multiplier of 1.02 out of 2.0. For 2012, Mr. Neyland’s performance measure is calculated at 100% for the Shared Services business unit, resulting in a business unit multiplier of 1.11 out of 2.0.

For 2012, the business unit multipliers upon which the NEO’s STIP is calculated are included in the following tables. They reflect rounding and range from 0 to 2.0, with 1.0 meaning that the performance measure was met. The business units include portions of other Enbridge businesses.

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Gas Transportation
Performance Measure	Weight		Sub Measures & Weightings		Rating		Performance Multiplier
Safety		20%	Health & Safety Management System Leader Enhancements	5%		1.89		0.38
			Safety Observations	5%
			Total Recordable Injury Frequency	5%
			Preventable Motor Vehicle Accidents	5%
Operations & Integrity		20%	Plant Reliability	5%		1.10		0.22
			Integrity Management Program Inspections	5%
			Reportable Releases	5%
			Non-Reportable Releases	5%
Financial		40%	Adjusted Net Income of EEP Gas, Enbridge Offshore Assets and Joint Venture Gas Assets	40%		0.04		0.02
Employee Engagement & Compliance		20%	Health Risk Assessment Participation	5%		1.77		0.35
			Compliance Training Participation	5%
			SOX Compliance	5%
			Risk Compliance	5%
			Business Unit Performance Multiplier					0.97

Gas Development
Performance Measure	Weight			Sub Measures & Weightings		Rating		Performance Multiplier
Operations, Safety & Integrity		25	%	Transition of Cabin Plant	5%		1.79		0.45
				HSMS Leader Enhancements	2.5%
				Safety Observations	2.5%
				Total Recordable Injury Frequency	2.5%
				Preventable Motor Vehicle Incidents	2.5%
				OSHA Recordable Incidents	2.5%
				Motor Vehicle Incidents	2.5%
				Environmental Regulatory Compliance	5%
Financial		40	%	Budget Earnings	40%		0.09		0.03
Business Development Activities		35	%	Contracting Strategies & New Investments	35.0%		2.00		0.70
				Business Unit Performance Multiplier					1.18

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Shared Services
Performance Measure	Weight		Sub Measures & Weightings		Rating		Performance Multiplier
Safety		20%	Health & Safety Management System Leader Enhancements	5%		1.89		0.38
			Safety Observations	5%
			Total Recordable Injury Frequency	5%
			Preventable Motor Vehicle Accidents	5%
Operations & Integrity		20%	Plant Reliability	5%		1.10		0.22
			Integrity Management Program Inspections	5%
			Reportable Releases	5%
			Non-Reportable Releases	5%
Financial		40%	Adjusted Net Income of EEP gas and Enbridge offshore assets	20%		0.41		0.16
			Adjusted Net Income of EEP liquids and Enbridge liquid pipelines	20%
Employee Engagement & Compliance		20%	Health Risk Assessment Participation	5%		1.77		0.35
			Compliance Training Participation	5%
			Sox Compliance	5%
			Risk Compliance	5%
Business Unit Performance multiplier								1.11

Liquids Pipelines
Performance Measure	Weight		Sub Measure % Weightings			Rating		Performance Multiplier
Environmental, Health & Safety		15%	Total Recordable Injury Frequency	3.75%			1.2		0.18
			Motor Vehicle Incidents	3.75%
			Health & Safety Incident Investigation & Corrective Actions	3.75%
			Safety Observations	3.75%
Governance & Compliance		5%	Governance Composite	5%			1.6		0.08
Financial		50%	Enbridge Liquids Pipelines Earnings	29%			1.2		0.59
			EEP Liquids Pipelines Earnings	8.5%
			Enbridge Pipelines Saskatchewan Inc. Earnings	2.5%
			Enbridge Liquids Pipelines Growth	10%
Pipeline Integrity		12%	Inspection and Remediation Programs	12%			0.9		0.10
Leak Detection		4%	Line Segment Improvements	4%			1.9		0.08
Operational Risk Management		4%	Framework, Initiative, & Compliance System	4%			1.5		0.06
Customer Satisfaction		5%	Capacity, Quality & Degradation	5%			1.8		0.09
Employee Retention & Development		5%	Employee Retention	2.5%			1.9		0.09
			Employee Attraction	2.5	%
Business Unit Performance multiplier									1.27

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Major Projects
Performance Measure	Weight		Sub Measures & Weightings	Rating		Performance Multiplier
Schedule		32%	Reach key milestone and forecast in-service delivery		1.14		0.36
Cost		24%	Development and execution of projects relative to budget		1.62		0.39
Quality		10.5%	Quality standards throughout lifecycle		1.78		0.19
Compliance		9.5%	Compliance with regulation and protection of the environment		1.65		0.16
Safety		14%	Leading and lagging measures to achieving best-in-class performance		1.14		0.16
People		10%	Employee attraction, retention and engagement		2.00		0.20
			Performance Multiplier				1.46
			Management Adjustment(1)				0.07
			Business Unit Performance Multiplier				1.53

(1) Management approved an adjustment due to Major Projects exceeding all targets.

Individual Performance

Each of the NEOs establishes individual goals at the beginning of each year by which individual performance is measured. These goals are based on areas of strategic and operational emphasis related to their respective portfolios, development of succession candidates, employee engagement, community involvement and leadership. The level of attainment of individual performance goals was recommended to the HRC Committee by Leon A. Zupan, who at the time was EEP’s Executive Vice President—Gas Pipelines, for Messrs. Maki, McGill and Neyland.

Summary of 2012 Performance Multipliers

The following table summarizes the corporate, business unit and individual performance multipliers for each executive, associated weights and overall performance multiplier result:

NEO	Corporate Performance (a) (Weight x Multiplier)		Business Unit Performance (b) (Weight x Multiplier)		Individual Performance (c) (Weight x Multiplier)		Overall Performance Multiplier (a+b+c)
Mark A. Maki		25% x 1.20 = 0.30		50% x 1.04 = 0.52		25% x 1.60 = 0.40		1.22
Terrance L. McGill		25% x 1.20 = 0.30		50% x 1.02 = 0.51		25% x 1.55 = 0.39		1.20
Stephen J. Neyland		25% x 1.20 = 0.30		50% x 1.11 = 0.56		25% x 1.65 = 0.41		1.27

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Based on the overall performance multiplier determined from the above table, short term incentive awards for our executives were calculated as follows:

NEO	Base Salary (a)		Target (b)			Overall Performance Multiplier (c)		Calculated STIP (1) =(a) x (b) x (c)		Actual STIP
Mark A. Maki	$	335,300		40	%		1.22	$	163,626	$	183,630
Terrance L. McGill		369,850		40	%		1.20		177,528		177,160
Stephen J. Neyland		237,930		35	%		1.27		105,760		120,550

(1) The calculated STIP may differ from the amounts presented due to rounding.

The leader of the Gas Transportation business unit, which was Mr. Leon Zupan in 2012, may recommend adjustments to the calculated STIP for Mssrs. Maki, McGill and Neyland, which recommendations are reviewed by Enbridge’s executive leadership team for fairness and consistency with enterprise-wide compensation. Messrs. Maki and Neyland received additional STIP awards above the computed amounts as a result of exceptional performance and contribution to Enbridge and to us.

Medium and Long-Term Incentives

Enbridge has four plans that make up its medium and long-term incentive program for senior management:

• A performance stock unit plan, or PSUP, which includes three-year phantom shares with performance conditions that impact payout;

• A performance-based stock option plan, or PSOP, that includes eight-year options to acquire Enbridge common shares with performance and time vesting conditions;

• An incentive stock option plan, or ISOP, which includes 10-year stock options to acquire Enbridge common shares with time vesting conditions; and

• A restricted stock unit plan, or RSUP, which grants Restricted Stock Units, or RSUs, to director and manager-level employees on an annual basis. RSUs have the same value as a common share of Enbridge stock, but are not traded in external financial markets. Mr. Neyland is the only NEO that participated in this plan for the year ended December 31, 2010.

Only the Enbridge executive leadership team are eligible to receive grants under the PSOP and therefore none of our NEOs are eligible to receive these grants.

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Enbridge believes that the combination of these medium and long-term incentive plans aligns a component of executive compensation with the interests of Enbridge shareholders beyond the current year. A significant percentage of the value of the annual long-term incentive awards to the NEOs is contingent on meeting performance criteria, share price targets under the PSOP and performance measures under the PSUP. Specifically, when earnings targets are achieved, the share price increases over the long term and when Enbridge common shares perform well relative to its peer organizations, the value of the medium and long-term incentive is maximized for the executives while also benefitting shareholders. The mix of medium and long-term incentive programs and total target medium and long-term incentive opportunity, expressed as a percentage of base salary, are as follows:

	Amount Each Plan Contributes to Total Target Grant(1)
NEO	Target Medium & Long-term Incentive Grant(1)			Performance Stock Units			Performance- Based Stock Options		Incentive Stock Options
Mark A. Maki		85.0	%		25.5	%		—		59.5	%
Terrance L. McGill		85.0	%		25.5	%		—		59.5	%
Stephen J. Neyland		70.0	%		21.0	%		—		49.0	%

(1) All values are expressed as percentages of base salary.

Actual award values, expressed as a percentage of base salary, range between 0% and 200% of the target medium and long-term incentive opportunity, based on individual performance history, succession potential, retention considerations and market competitiveness.

PSUP

The PSUP is a three-year performance-based unit plan. Performance measures and targets are established at the start of the term to reflect the mid-term objectives of Enbridge in the execution of its strategic plan. Achievement of the performance targets can decrease or increase the final award value in a range of 0% to 200%. PSUs do not involve the issuance of any shares of common stock of Enbridge. Throughout the term, units are added to the grants as if dividends were received and reinvested into additional units based on the actual dividend rate for shares of Enbridge common stock. Awards are granted annually and paid in cash at the end of a three-year term based on two performance criteria that were established for the 2012 grants, each of which weighted 50%: EPS and price to earnings ratio, or P/E Ratio.

The EPS performance reflects Enbridge’s commitment to its shareholders to achieve earnings that meet or exceed industry growth rates. Enbridge established the EPS target to reflect performance that would be consistent with the average growth rate forecast of peer companies over a comparable time period. The EPS required to achieve a two multiplier (the maximum) would demonstrate achievement of compound annual growth consistent with exceptional industry growth rate and would represent exceptional performance to the investment community. Performance must at least meet 3% compound annual growth in EPS for a threshold payment, below which the multiplier would be zero.

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The second performance criterion is the Enbridge P/E Ratio relative to a selected comparator group of companies. Enbridge’s price to earnings performance has historically been very strong, therefore performance below the median of the peer group results in a multiplier of zero, performance between the median and 75^th percentile results in a multiplier of one and performance above the 75^th percentile results in a multiplier of two. The following table presents the comparator group for the P/E Ratio.

Price/Earnings Ratio—Comparator Group of Companies
Ameren Corporation Canadian Utilities Limited Centerpoint Energy, Inc. Emera Incorporated Fortis Inc. National Fuel Gas Company NiSource Inc.	OGE Energy Corp. ONEOK, Inc. PG&E Corporation Sempra Energy Spectra Energy Corp. TransAlta Corporation TransCanada Corporation

This peer group of companies was selected because they are all capital market competitors of Enbridge, have a similar risk profile and are in a comparable sector.

PSOP

None of Messrs. Maki, McGill, Neyland,                      or                      are eligible to receive performance stock options.

ISOP

Regular stock options focus the Enbridge executives on increasing shareholder value over the long-term through common share price appreciation. Stock options are granted annually to Enbridge executives entitling them to acquire Enbridge common shares at a price defined at the time of grant. These options become exercisable over a period of four years at a rate of 25% per year and the term of the grant is ten years.

RSUP

The RSUP is a plan that awards RSUs to director and manager-level employees based on their base salary, an RSU target incentive opportunity and the share price of Enbridge common stock. Additionally the number of units can be adjusted for factors including performance, skill, potential and external market competitiveness. Grants are made infrequently, typically in February, effective January 1 of each year and have a 35-month term. Throughout the term, units are added to the grants as if dividends were received and reinvested into additional units based on the actual dividend rate for common shares of Enbridge stock. At the end of the term, the units are paid in cash based on the weighted average price of an Enbridge common share on the NYSE for 20 trading days prior to the end of the term. Mr. Neyland is the only NEO that participated in this plan within the last three years, and he participated only for the year ended December 31, 2010.

193

Service Agreements and Allocation of Compensation to the Partnership

As discussed above, EEP provides managerial, administrative, and operational services to us pursuant to the intercorporate services agreement, which services are ultimately provided through services agreements among EEP, Enbridge Management and Enbridge and its affiliates. Pursuant to the intercorporate services agreement, we reimburse EEP for our allocated portion of the costs of such services. Through a services agreement between our general partner and EEP, we are charged for the services of executive management resident in the United States, including Messrs. Maki, McGill, Neyland,                      and                     .

EEP determines a budgeted allocation rate for our NEOs’ compensation in accordance with the terms of the agreements it has entered into with Enbridge Management and Enbridge and its affiliates and provides reimbursement for costs of services based on allocation method provided under those agreements. Since the allocation rate is estimated, the actual time spent by an NEO on behalf of EEP (which includes services to us) may vary from the budgeted allocation rate, and EEP may be allocated more or less of that NEO’s compensation than the actual percentage of his time spent on its behalf in a given year. The amount of our NEOs compensation that, following the consummation of this offering, will be allocated by EEP to us is determined in accordance with the terms of the intercorporate services agreement. For additional information, regarding out intercorporate services agreement, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Intercorporate Services Agreement.”

The compensation of our NEOs included in the tables below is established by Enbridge as described above. We have included in the following tables the full amount of compensation and related benefits provided for each of the NEOs for 2012, 2011 and 2010, together with the budgeted estimate of the approximate time spent by each NEO on EEP’s behalf and the approximate amount of compensation cost allocated to EEP for the years ended December 31, 2012, 2011 and 2010, as applicable. Since the amount of NEO compensation allocated to EEP is based on estimates of time spent on EEP’s behalf by the particular NEO, the compensation amounts allocated to EEP may not exactly reflect the amount of time that a certain NEO devoted to EEP’s business. We are a newly established partnership that was formed in May 2013. Therefore, no specific amounts of such compensation were allocated to us for 2012, 2011 or 2010.

194

SUMMARY COMPENSATION TABLE

Name and (1) Principal Position (a)	Year (b)		Salary ($) (c)		Stock Awards(1) ($) (e)		Option Awards(2) ($) (f)		Non-Equity Incentive Plan Compen- sation(3) ($) (g)		Change in Pension Value and Nonqualified Deferred Compen- sation Earnings ($) (h)		All Other Compen- sation(4) ($) (i)		Total ($) (j)		Approximate Percentage of Time Devoted to Enbridge Energy Partners, L.P. (%)		Approximate Amount Allocated to Enbridge Energy Partners, L.P. ($)
Mark A. Maki		2012		344,475		590,857		289,938		183,630		813,000		34,246		2,256,146		95		1,896,178
President and Director		2011		336,588		535,317		237,103		216,340		781,000		33,996		2,140,344		86		1,974,238
		2010		294,639		447,118		159,653		202,740		370,000		33,996		1,508,146		77		1,336,788
Terrance L. McGill		2012		367,660		712,584		415,786		177,160		371,000		35,822		2,080,012		90		1,809,538
Chief Operating Officer and Director		2011		366,309		734,843		435,372		237,060		442,000		35,853		2,251,437		86		2,080,741
		2010		354,348		707,024		291,550		223,010		281,000		35,853		1,892,785		77		1,692,380
Stephen J. Neyland		2012		241,198		249,187		163,217		129,750		162,000		33,532		978,884		90		824,613
Vice President—Finance		2011		234,998		151,454		125,248		139,150		157,000		33,496		841,346		86		763,286
		2010		213,027		75,566		81,055		96,360		75,000		24,897		565,905		79		491,208
		2012
		2011
		2010
		2012
		2011
		2010

(1) The compensation expense associated with Performance Stock Units, or PSUs, for each NEO, and the Restricted Stock Units, or RSUs with respect to Mr. Neyland that are reflected in this column represent one-third of the market value for each year the PSUs and RSUs are outstanding and are measured based on the number of respective units granted, dividends reinvested, cliff-vested, the actual or forecast performance multiplier with respect to the PSUs, and the market value or payout amount at the end of each period. For example, 2012 includes one-third of the market values for PSUs and RSUs issued in 2012, 2011 and 2010. In 2012, the compensation expense recorded for PSUs granted in 2012, 2011 and 2010 include performance multipliers for the respective years, which are estimated at December 31, 2012 to be 2.0 and the actual multiplier of 2.0 for 2011 and 2010 based upon the expected or achieved levels of performance in relation to established targets for each year. RSUs do not have performance multipliers used in determining the payout amount. For years prior to the year a payout is made, a performance multiplier is forecast based upon the progress made in attaining the established performance criteria unless the actual multiplier has been determined. Refer also to Footnote 3 of the Grants of Plan—Based Awards table for additional discussion regarding the PSUs. Mr. Neyland received RSUs in 2010. The market value for each PSU and RSU grant represents the weighted average closing price of an Enbridge common share as quoted on the NYSE for the USD denominated PSUs for the 20 consecutive days prior to the end of the performance period. PSUs granted for 2012, 2011 and 2010 were denominated in both USD and CAD, while RSUs granted to Mr. Neyland are denominated in only USD. The PSU expense in CAD is converted to USD based on the average exchange rate for the 20 trading days prior to the end of the performance period December 31, 2012, 2011 and 2010, respectively. The PSUs and RSUs were granted on January 1, 2012, 2011 and 2010, respectively. The actual payout amounts for the 2009 PSUs that vested in 2012 were based on average share prices of $42.27 USD and $41.69 CAD, for the respective USD denominated PSUs and CAD denominated PSUs and $39.39 USD for the 2009 RSUs that vested in 2012. Compensation expense as reported in the Summary Compensation Table above for Stock Awards has been determined using the following assumptions:

195

	2012		2011		2010(a)		2009(a)		2008(a)
End of Period Market Value USD	$	42.27	$	35.75	$	27.71	$	22.41	$	15.70
End of Period Market Value CAD	$	41.69	$	36.38	$	27.92	$	23.57	$	19.36
20-day average $1CAD to USD exchange rate before January 1	$	1.0104	$	0.9768	$	0.9927	$	1.0544	$	1.2343
Exchange rate on payout date		N/A		N/A		N/A		N/A		N/A
Performance multiplier		N/A		N/A		N/A		N/A		2.00
Assumed performance multiplier		2.00		2.00		2.00		2.00		N/A

(a) Where appropriate, prices adjusted for the May 2011 Enbridge stock split.

(2) Under the authoritative accounting provisions for share-based payments, the annual expenses for option awards that are granted under the Enbridge Incentive Stock Option Plan (2007), or ISOP, and the PSOP are determined by computing the fair value of the options on the grant date using the Black-Scholes option pricing model. The following assumptions were used in computing the fair value of the options on the grant date for the respective option pricing model employed and the indicated year:

	ISOP									PSOP
Assumption	2012			2011			2010			2012			2011	2010
Expected option term in years		6			6			6			8		N/A	N/A
Expected volatility		22.80	%		22.40	%		34.10	%		16.10	%	N/A	N/A
Expected dividend yield		2.95	%		3.41	%		3.64	%		2.80	%	N/A	N/A
Risk-free interest rate		1.17	%		2.80	%		2.92	%		1.60	%	N/A	N/A

The fair value of options granted as computed using the above assumptions is expensed over the shorter of the vesting period for the options and the period to early retirement eligibility. The exercise price and fair value information for all option grants has been converted to USD using the exchange rates as set forth in the tables below. The fair values of all grants on the grant date have been converted to USD using the average exchange rates, representing the exchange rate for the period during which the expense was recognized.

	ISOP						PSOP
	2012		2011		2010(a)		2012		2011	2010
Exercise price in CAD	$	38.34	$	28.78	$	23.30	$	39.34	N/A	N/A
Exercise price in USD	$	38.65	$	28.99	$	21.97	$	39.77	N/A	N/A
Grant date exchange rate for $1 USD	$	0.9888	$	0.9885	$	1.0426	$	0.9891	N/A	N/A

(a) Where appropriate, prices adjusted for the May 2011 Enbridge stock split.

	ISOP						PSOP
	2012		2011		2010(a)		2012		2011	2010
Vesting period in years		4		4		4		8	N/A	N/A
Option fair value on grant date in CAD	$	5.00	$	4.00	$	4.66	$	4.25	N/A	N/A
Option fair value on grant date in USD	$	6.11	$	5.11	$	5.95	$	4.30	N/A	N/A
Average full year exchange rate for $1 USD	$	0.9996	$	0.9891	$	1.0299	$	0.9884	N/A	N/A

(a) Where appropriate, fair values adjusted for the May 2011 Enbridge stock split.

(3) Non-equity incentive plan compensation represents awards that are paid in February of each year for amounts that are earned in the immediately preceding fiscal year under the Enbridge STIP as discussed in the above Compensation Discussion and Analysis. The Non-Equity Incentive Plan Compensation for Mr. Neyland includes an additional amount received during 2012 that was awarded for additional effort and personal commitment.

(4) The table which follows labeled “All Other Compensation” sets forth the elements comprising the amounts presented in this column.

196

ALL OTHER COMPENSATION

(For the years ended December 31, 2012, 2011 and 2010)

Name	Year		Flexible Benefits(1) $		401(k) Matching Contributions(2) $		Other Benefits(3) $		Total
Mark A. Maki		2012		20,000		12,500		1,746		34,246
		2011		20,000		12,250		1,746		33,996
		2010		20,000		12,250		1,746		33,996
Terrance L. McGill		2012		20,000		12,500		3,322		35,822
		2011		20,000		12,250		3,603		35,853
		2010		20,000		12,250		3,603		35,853
Stephen J. Neyland		2012		20,000		11,786		1,746		33,532
		2011		20,000		11,750		1,746		33,496
		2010		12,500		10,651		1,746		24,897

(1) Flexible benefits for our NEOs represent a perquisite allowance that is paid in cash as additional compensation.

(2) Our NEOs that participate in the Enbridge Employee Services, Inc. Savings Plan, referred to as the 401(k) Plan, may contribute up to 50% of their base salary, which is matched up to 5% by Enbridge. Both individual and matching contributions are subject to limits established by the Internal Revenue Service. Enbridge contributions are used to purchase Enbridge common shares at market value and employee contributions may be used to purchase Enbridge common shares or 23 designated funds.

(3) Other benefits include parking for our NEOs.

Enbridge does not maintain any compensation plans for the benefit of the NEOs under which equity interests in EEP or Enbridge Management may be awarded. However, Enbridge allocates to EEP a portion of the compensation expense it recognizes in accordance with the authoritative guidance for share-based compensation in connection with recording the fair value of its performance and restricted stock units and outstanding stock options granted to certain of its officers, including the NEOs. The costs EEP is charged with respect to option grants represent a portion of the costs determined in accordance with U.S. GAAP. Following the consummation of this offering, we will reimburse EEP for an allocated portion of these costs in accordance with the terms of the intercorporate services agreement.

The PSUs are granted to the NEOs pursuant to the PSUP and stock options are granted pursuant to the ISOP and the PSOP. Awards under these plans provide long-term incentive and are administered by the HRC Committee of Enbridge. Although stock options remain outstanding that were granted under the Enbridge Incentive Stock Option Plan (2002), no further stock options will be granted under this plan. The performance stock units granted in 2010 through 2012 to our NEOs are denominated in USD. The three tables which follow set forth information concerning performance stock units and stock options granted during the year ended December 31, 2012, outstanding at December 31, 2012 and the number of awards vested and exercised during the year ended December 31, 2012 by each of the NEOs.

197

GRANTS OF PLAN-BASED AWARDS

	Plan Name(1) (b)		Approval Date (b)		Grant Date (b)		Estimated Future Payouts Under Non-Equity Incentive Plan Awards(2)						Estimated Future Payouts Under Equity Incentive Plan Awards(3)						All Other Option Awards: Number of Securities Underlying Options(4)(5) (#) (j)		Exercise or Base Price of Option Awards (4)(5) ($/Sh) (k)		Grant Date Fair Value of Stock and Option Awards (3)(4)(5) ($) (l)
Name (a)									Target ($) (d)		Maximum ($) (e)		Threshold (#) (f)		Target (#) (g)		Maximum (#) (h)
Mark A. Maki		PSUP		1-Feb-12		1-Jan-12		—		—		—		2,781		4,450		8,900		—		—		159,088
		ISOP		1-Feb-12		2-Mar-12		—		—		—		—		—		—		61,650		38.65		376,682
		STIP		1-Feb-13		1-Feb-13		—		134,120		268,240		—		—		—		—		—		—
Terrance L. McGill		PSUP		1-Feb-12		1-Jan-12		—		—		—		3,094		4,950		9,900		—		—		176,963
		ISOP		1-Feb-12		2-Mar-12		—		—		—		—		—		—		68,050		38.65		415,786
		STIP		1-Feb-13		1-Feb-13		—		147,940		295,880		—		—		—		—		—		—
Stephen J. Neyland		PSUP		1-Feb-12		1-Jan-12		—		—		—		2,250		3,600		7,200		—		—		128,700
		ISOP		1-Feb-12		2-Mar-12		—		—		—		—		—		—		39,100		38.65		238,901
		STIP		1-Feb-13		1-Feb-13		—		83,276		166,551		—		—		—		—		—		—

(1) The abbreviated plan names are defined as follows:

a. PSUP refers to the Enbridge Performance Stock Unit Plan (2007), an equity-based incentive plan.

b. ISOP refers to the Enbridge Incentive Stock Option Plan (2007), a qualified stock option plan.

c. STIP refers to the Enbridge Short Term Incentive Plan (2006), a non-equity performance-based incentive plan.

(2) The estimated future payouts under non-equity incentive award plans represents awards under the Enbridge STIP as presented above in the Compensation Discussion and Analysis under the section labeled Short-Term Incentive Plan.

(3) Our NEOs are eligible to receive annual grants of PSUs, under the PSUP, an equity-based, long-term incentive plan, administered by a committee of the board of directors of Enbridge. The initial value of each of these PSUs on the grant date is equivalent to the volume weighted average closing price of one Enbridge common share as quoted on the NYSE for the 20 trading days immediately preceding the start of the performance period. The initial PSUs granted are increased for quarterly dividends paid during the three-year period on an Enbridge common share that are reinvested in additional PSUs. Awards under the PSUP are paid out in cash at the end of a three-year performance cycle based on: (1) an EPS target for Enbridge based on the long range plan of the organization and (2) the P/E Ratio of an Enbridge common share relative to a defined group of peer organizations established in advance by a committee of the board of Enbridge. Payments under the PSUP may be increased up to 200% of the original award when Enbridge exceeds the established targets. If Enbridge fails to meet threshold performance levels, no payments are made under the PSUP. Notional dividends are paid on the PSUs which are invested in additional PSUs at the then current market price for one share of Enbridge common stock, which are not included in the estimated future payout amounts, but have been included in the compensation associated with stock awards in the Summary Compensation Table. Enbridge does not issue any common shares in connection with the PSUP.

The threshold at which PSUs are paid out represents 62.5% of the number of PSUs initially granted increased by additional PSUs resulting from reinvested dividends and is the lowest level at which PSUs will be paid out based on the performance criteria discussed above. The target level at which PSUs are issued represents 100% of the number of PSUs initially granted increased by additional PSUs resulting from reinvested notional dividends and attainment of the established performance criteria. The maximum level at which PSUs may be issued is 200% of the number of PSUs initially granted and may occur when Enbridge exceeds the established performance criteria. PSUs vest at the end of a three year performance period that begins on January 1 of the year granted and during the term the PSUs are outstanding, a liability and expense are recorded by Enbridge based on the number of PSUs outstanding and the current market price of an Enbridge common share with an assumed performance multiplier that is determined quarterly based on progress towards achieving the established performance criteria, until the end of the performance period at which point the performance multiplier is known. The grant date fair value for each PSU granted to each of our NEOs in 2012 was $35.75 USD, representing the volume weighted average closing price of one Enbridge common share as quoted on the NYSE for the 20 trading days immediately preceding the start of the performance period that began on January 1, 2012.

(4) The ISOP is administered by a committee of the Enbridge board of directors and if an option is granted during a trading blackout period, the exercise price of an option grant is determined as the weighted average trading price of an Enbridge common share on the NYSE for the five trading days immediately prior to the effective date of the option. In the event an option grant is granted during a period a trading blackout is not in effect, the exercise price of the option grant is equal to the last reported sales price on the NYSE for the day immediately preceding the grant date. During 2012, each of the NEOs received grants of Enbridge incentive stock options that upon exercise may be exchanged for an equivalent number of shares of Enbridge common stock. The exercise price of the incentive stock options at the time of grant $38.65 USD.

The amounts included as the grant date fair value for the 2012 incentive stock option awards represent the amount determined by computing the fair value of the options in accordance with the authoritative guidance for share-based payments on the grant date using the Black-Sholes option pricing model with the following assumptions:

198

USD Option Value

6 years expected term;

22.8% expected volatility;

2.95% expected dividend yield; and

1.17% risk free interest rate.

The fair value of options granted as computed using these assumptions is $6.11 USD. The grant date fair value is expensed over the shorter of the vesting period for the options, generally four years, and in the year granted for employees age 55 and over and eligible for early retirement. Mr. McGill was aged 55 or over and eligible for early retirement as of the grant date and, as a result, the grant date fair value of options he was awarded is expensed in the year granted.

(5) The Enbridge Performance Stock Option Plan is administered by the HRC Committee and if a performance option is issued during a trading blackout period, the exercise price of a performance option grant is determined as the weighted average trading price of an Enbridge common share on the Toronto Stock Exchange, or the TSX, or NYSE for the five trading days immediately prior to the effective date of the performance option. In the event an option grant is issued during a period a trading blackout is not in effect, the exercise price of the performance option grant is equal to the last reported sales price on the TSX or NYSE for the day immediately preceding the grant date. PBSOs are similar to the incentive stock options, except that the quantities become exercisable subject to both the achievement of specified common share price targets and time requirements.

The term of each grant is eight years provided the three common share price targets are met within a defined time period. The options vest 20% per year over five years, starting on the first anniversary of the grant date and must meet the first common share price target to receive any options. PBSOs are granted on an infrequent basis and provided the eligible NEO the opportunity to acquire one Enbridge common share for each option held when the specified term and performance criteria are met. During 2012, Messrs. Monaco, Wuori and Zupan received grants of Enbridge performance stock options that upon exercise may be exchanged for an equivalent number of shares of Enbridge common stock. The common share price targets for the 2012 PSOP are $48.00 CAD, $53.00 CAD and $58.00 CAD, which must be met by February 2019 and will have weighted vesting at a 40%, 40% and 20% based on each target price met. The exercise price of the PBSOs at the time of grant was $39.34 CAD which has been converted into USD using an exchange rate of $0.9891 = $1 USD, representing the noon buying rate in New York for transfers of CAD on the grant date of August 15, 2012.

The amounts included as the grant date fair value for the 2012 PBSO awards represent the amount determined by computing the fair value of the options under ASC 718 on the grant date using the Bloomberg barrier option valuation model with the following CAD assumptions:

 • 8 years expected term;

 • 16.10% expected volatility;

 • 2.80% expected dividend yield; and

 • 1.60% risk free interest rate

The fair value of options granted as computed using these assumptions is $4.25 CAD which has been converted to USD using an exchange rate of $0.9891 CAD = $1 USD, representing the noon buying rate in New York for transfers of CAD on the grant date of August 15, 2012, which equates to a grant date fair value of $4.30 USD per option granted. The grant date fair value is expensed over the shorter of the vesting period for the options (generally five years) and the period to early retirement eligibility.

199

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END

	Option Awards								Stock Awards
Name (a)	Number of Securities Underlying Unexercised Options (#) Exercisable (b)		Number of Securities Underlying Unexercised Options (#) Unexercisable(1)(2) (c)		Option Exercise Price(3) ($) (e)		Option Expiration Date(1) (f)		Equity Incentive Plan Awards: Number of Unearned Shares, Units  or Other Rights That Have Not  Vested(4) (#) (i)		Equity Incentive Plan Awards: Market or Payout of Value Value  of Unearned Shares, Units or Other Rights That Have Not  Vested ($) (j)
Mark A. Maki		—		61,650		38.65		2-Mar-22		4,579		396,749
		19,100		57,300		28.99		14-Feb-21		6,367		551,642
		17,000		17,000		21.97		16-Feb-20
		30,650		15,050		15.80		25-Feb-19
		5,200		—		20.17		19-Feb-18
Terrance L. McGill		—		68,050		38.65		2-Mar-22		5,094		441,328
		21,300		63,900		28.99		14-Feb-21		6,579		570,030
		24,500		24,500		21.97		16-Feb-20
		74,250		24,750		15.80		25-Feb-19
		99,000		—		20.17		19-Feb-18
Stephen J. Neyland		—		39,100		38.65		2-Mar-22		3,705		320,966
		—		33,450		28.99		14-Feb-21		3,396		294,209
		—		7,700		21.97		16-Feb-20
		—		7,750		15.80		25-Feb-19

(1) Each ISO award has a 10-year term and vests pro-rata as to one fourth of the option award beginning on the first anniversary of the grant date; thus the vesting dates for each of the option awards in this table can be calculated accordingly. As an example, for Mr. Maki’s grant that expires on February 14, 2021, the grant date would be 10 years prior or February 14, 2011 and as a result, the remaining unexercisable amounts become fully vested on February 14, 2015 representing four years following the grant date.

(2) PSOs were provided to certain of our NEOs on September 15, 2002, August 15, 2007, February 19, 2008 and August 15, 2012 and are similar to the incentive stock options, except that the quantities that become exercisable are subject to both time and performance requirements. PSOs are granted on an infrequent basis and provide the eligible NEO the opportunity to acquire one Enbridge common share for each option held when the specified time and performance conditions are met. The PBSOs granted September 16, 2002, became exercisable, as to 50 % of the grant, when the price of an Enbridge common share exceeded $30.50 for 20 consecutive days during the period September 16, 2002 to September 16, 2007, and became exercisable as to 100% when the price of an Enbridge common share exceeded $35.50 for 20 consecutive days during the same period. As a result of achieving the established performance criteria, the initial five year term of the options was extended to 12 years expiring on August 15, 2015. Upon the performance hurdles being met, the PBSOs are also time vested 20% annually over five years. As of December 31, 2012, both common share price targets for the PBSOs granted August 15, 2007 and February 19, 2008 were met, therefore 100% of the 2007 grant and 80% of the 2008 grant were vested or exercisable and none of the target common share prices were met for the PSOs in 2012 so no grants were vested or exercisable.

(3) The exercise prices of the ISOs and PBSOs issued during 2006 and prior years are denominated in CAD and have been adjusted for the noon exchange rate on the date of grant. Where appropriate, all exercise prices and valuation prices prior to 2011 have been adjusted for the April 2011 Partnership stock split and Enbridge’s May 2011 stock split.

(4) The unearned Enbridge common shares, units or other rights that have not vested under stock awards represent PSUs for which the performance criteria discussed in Footnote 3 of the Grants of Plan-Based Awards table have not been achieved. The PSUs become vested upon achieving the established performance criteria. The amounts represented in the column are the number of units that have not vested at the closing common share price of one Enbridge common share on the NYSE at $43.32 per share or the TSX at $43.02 per common share converted to USD of $43.24 per share at the conversion rate of $0.9949 CAD = $1 USD representing the weighted average noon rate for 20 trading days immediately preceding the performance period that began on January 1, 2012. The market or payout values presented assume a performance multiplier of 2.0 for PSUs granted in 2012, 2011 and 2010, which amounts represent the maximum level attainable based on forecasts of performance at December 31, 2012.

200

OPTION EXERCISES AND STOCK VESTED

	Option Awards				Stock Awards
Name (a)	Number of Shares Acquired on Exercise (#) (b)		Value Realized on Exercise ($) (c)		Number of Shares Acquired on Vesting(1)(2) (#) (d)		Value Realized on Vesting(1)(3) ($) (e)
Mark A. Maki		70,000		1,409,664		6,588		555,634
Terrance L. McGill		111,400		2,369,166		9,224		777,888
Stephen J. Neyland		34,350		710,602		1,977		77,846

(1) For Mr. Neyland, the number of common shares acquired on vesting for stock awards represents the number of RSUs issued in 2009 increased by the number of additional units obtained from reinvesting dividends received. The value realized on vesting is determined based on the weighted average price of Enbridge stock for 20 trading days prior to the end of the term on December 1, 2012, which was $39.39 USD.

(2) The number of Enbridge common shares acquired on vesting for stock awards represents the number of PSUs issued in 2010 and the related dividends paid that were used to acquire additional PSUs, all of which matured on December 31, 2012. As discussed in Footnote 3 of the Grants of Plan-Based Awards table, no common shares are issued with respect to the PSUs that become vested; rather, cash is paid in an amount based on the value of an Enbridge common share at the maturity date and the level of achievement of the established performance goals. The payout for the PSUs granted in 2010 occurred during the first quarter of 2013.

(3) The value realized on vesting is determined based on the final value of an Enbridge common share of $42.17 USD. In each case the common share price is multiplied by a 2.0 performance factor multiplied by the number of PSUs, and is then converted to USD, as applicable, using an exchange rate of $0.9897 CAD = $1USD for the PSUs that matured on December 31, 2012.

Pension Plan

Enbridge sponsors the Enbridge Employee Services, Inc. Employees’ Pension Plan, or QPP. This plan provides defined pension benefits and cash balance benefits to employees in the United States and is non-contributory. Enbridge also sponsors a supplemental nonqualified retirement plans in the United States, referred to as US SPP, which provide defined pension benefits for the NEOs in excess of the tax-qualified plans’ limits. We collectively refer to the QPP and the US SPP as the Pension Plans. Defined pension benefits under the Pension Plans are based on the employees’ years of service and final average remuneration with an offset for Social Security benefits, while cash balance benefits are based on annual payout and interest credits to notional member accounts. Defined pension benefits are partially indexed to inflation after a named executive officer’s retirement.

For service prior to January 1, 2000, the Pension Plans provide a yearly pension payable in the normal form (60% joint and last survivor) equal to: (a) 1.6% of the average of the participant’s highest annual salary during three consecutive years out of the last ten years of credited service multiplied by (b) the number of credited years of service. The pension is offset, after age 65, by 50% of the participant’s Social Security benefit, pro-rated by years in which the participant has both credited service and Social Security coverage. An unreduced pension is payable if retirement is after age 55 with 30 or more years of service, or after age 60. Early retirement reductions apply if a participant retires and does not meet these requirements. Retirement benefits are indexed at 50% of the annual increase in the United States consumer price index.

For service after December 31, 1999, the Pension Plans provide for senior management employees, including the NEOs, a yearly pension payable in the normal form (60% joint and last survivor) equal to: (a) 2% of the sum of (i) the average of the participant’s highest annual base salary during three consecutive years out of the last ten years of credited service and (ii) the average of the participant’s three highest annual performance bonus periods, represented in each period by 50% of the actual bonus paid, in respect of the last five years of credited service, multiplied by (b) the number of credited years of service. An unreduced pension is payable if retirement is after age 55 with 30 or more years of service or after age 60. Early retirement reductions apply if a participant retires and does not meet these requirements. Retirement benefits paid from the Plan are indexed at

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50% of the annual increase in the consumer price index. For Mr. Neyland, QPP service after December 31, 2001 but prior to becoming a senior management employee includes 2.5 years of cash balance service, with annual pay credits based on his age and service with Enbridge.

Plan benefits that exceed maximum pension rules applicable to qualified plan benefits are paid from the US SPP. Other trusteed pension plans, with varying contribution formulae and benefits, cover the balance of employees.

The table below illustrates the total annual pension entitlements at December 31, 2012 assuming the eligibility requirements for an unreduced pension have been satisfied. The present value of the accumulated benefits has been determined under the accrued benefit valuation method with the following assumptions:

Discount rate	3.80% at year-end 2012
Salary increases	None
Inflation	2.50% per year
Retirement age	Age when first eligible for an unreduced pension(1)
Terminations	None
Mortality Rates:
Pre-retirement	None
Post-retirement	PPA generational annuitant and nonannuitant tables (UP-1994 with generational mortality improvements)

(1) This is age 60 for all executives except for Mr. Maki, who is eligible for an unreduced pension at age 55.

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PENSION BENEFITS

Name (a)	Plan Name (b)		Number of Years Credited Service (#) (c)		Present Value of Accumulated Benefit ($) (d)
Mark A. Maki		EI RPP		1.92		90,000
		EI SPP		1.92		181,000
		US QPP		24.40		1,666,000
		US SPP		24.40		1,243,000
Terrance L. McGill		US QPP		10.50		207,000
		US SPP		10.83		1,723,000
Stephen J. Neyland		US QPP		10.50		158,000
		US SPP		8.00		405,000

Our 2013 Long-Term Incentive Plan

We are a newly formed master limited partnership and have not previously granted equity incentive awards in us to any person. In addition, following the consummation of this offering, we do not currently expect that equity awards in us will be used to compensate any of our NEOs or any other employees of Enbridge or its affiliates who provide services to us. However, because we may choose to grant equity incentive awards in us at a future date, in connection with the offering our general partner intends to adopt the 2013 Midcoast Energy Partners, L.P. Long-Term Incentive Plan, or our LTIP, under which our general partner may issue long-term equity based awards to directors, officers and employees of our general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services for us. In the event we choose to grant any such awards, these awards will be intended to compensate the recipients thereof based on the performance of our common units and their continued service during the vesting period, as well as to align their long-term interests with those of our unitholders. We will be responsible for the cost of awards granted under our LTIP and all determinations with respect to awards to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof would be designated as the plan administrator. The following description reflects the terms that are currently expected to be included in the LTIP.

General

The LTIP will provide for the grant, from time to time at the discretion of the board of directors of our general partner or any delegate thereof, subject to applicable law, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP will limit the number of units that may be delivered pursuant to vested awards to common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are cancelled, forfeited, withheld to satisfy exercise prices or tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon

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specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement. Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

Distribution Equivalent Rights

The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Unit Awards

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Other Unit-Based Awards

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of another unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, another unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Source of Common Units

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

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Anti-Dilution Adjustments and Change in Control

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the administrator of the LTIP shall have discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number of units available under the LTIP and the kind of units or other securities available for grant under the LTIP. Furthermore, upon any such event, including a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) require awards to be surrendered in exchange for a cash payment or substitute other rights or property for the award, (iii) provide for the award to assumed by a successor or one of its affiliates, with appropriate adjustments thereto, (iv) cancel unvested awards without payment or (v) make other adjustments to awards as the administrator deems appropriate to reflect the applicable transaction or event.

Termination of Service

The consequences of the termination of a grantee’s membership on our general partner’s board of directors or other service arrangement will generally be determined by the plan administrator in the terms of the relevant award agreement.

Amendment or Termination of Long-Term Incentive Plan

The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP automatically terminates on the tenth anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.

Compensation of Our Directors

Our general partner did not have any, and paid no compensation to, members of its board of directors in 2012. Following the consummation of this offering, any employees of Enbridge or its affiliates who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers of our general partner or of Enbridge Management or EEP’s general partner, Enbridge or any of their affiliates or employees of Enbridge or any of its affiliates will receive compensation as “non-employee directors,” which is expected to have an annual value equal to $             payable in cash. In addition, the chair of each standing committee of our general partner’s board of directors will receive an additional annual cash retainer as follows: audit, finance and risk committee chair: $             ; conflicts committee chair: $             ; and other committee chair: $            . Further, each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law and will be reimbursed for all expenses incurred in attending to his or her duties as a director.

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SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of Midcoast Energy Partners, L.P. that will be issued upon the consummation of this offering and the related transactions and held by beneficial owners of 5% or more of the units, by each director and named executive officer of Midcoast Holdings, L.L.C., our general partner, and by all directors and executive officers of our general partner as a group and assumes the underwriters’ option to purchase additional common units from us is not exercised. The percentage of units beneficially owned is based on a total of              common units and subordinated units outstanding immediately following this offering.

The following table does not include any common units that directors and officers of our general partner and Enbridge Management may purchase in this offering through the directed unit program described under “Underwriting.”

Name of beneficial owner(1)	Common units to be beneficially owned	Percentage of common units to be beneficially owned		Subordinated units to be beneficially owned	Percentage of subordinated units to be beneficially owned			Percentage of total common units and subordinated units to be beneficially owned
EEP			%			100	%		%
Directors/Named Executive Officers
All Directors and Executive Officers as a group (     persons)			%				%		%

(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1100 Louisiana Street, Suite 3300, Houston, Texas 77002.

The following table sets forth the number of common units of EEP beneficially owned as of                     , 2013, except as otherwise noted, by each director and named executive officer of our general partner and by all directors and executive officers of our general partner as a group.

Name of beneficial owners	Amount and nature of beneficial ownership	Percent of total outstanding(1)
Directors/Named Executive Officers
			%
All Directors and Executive Officers as a group (     persons)			%

(1) Based on                      units outstanding as of                     , 2013.

* The percentage of shares beneficially owned by each director or each executive officer does not exceed 1% of the common shares outstanding. The percentage of shares beneficially owned by all directors and executive officers as a group does not exceed 1% of the common shares outstanding.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, the general partner and its affiliates will own              common units and              subordinated units representing a     % limited partner interest in us (or     % if the underwriters’ option to purchase additional common units is exercised in full). In addition, our general partner will own              general partner units representing a 2% general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation, and liquidation of Midcoast Energy Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation stage

The consideration received by our general partner and its affiliates prior to or in connection with this offering for the contribution of the assets and liabilities to us •              common units;

•              subordinated units;

•              general partner units representing a 2% general partner interest in us;

• the incentive distribution rights;

• a $         million cash distribution, funded with a portion of the net proceeds of the offering, in part to reimburse them for certain capital expenditures; and

• an additional $350.0 million cash distribution funded with borrowings under our revolving credit facility.

Operational stage

Distributions of available cash to our general partner and its affiliates We will generally make cash distributions of 98% to the unitholders pro rata, including EEP, as holder of an aggregate of              common units and              subordinated units, and 2% to our general partner, assuming it makes any capital contributions necessary to maintain its 2% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48% of the distributions above the highest target distribution level.

Assuming we generate sufficient distributable cash flow to support the payment of the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its

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affiliates would receive an annual distribution of approximately $         million on the 2% general partner interest and $         million on their common units and subordinated units (or $         million if the underwriters exercise in full their option to purchase additional common units from us) and $         million on their common units and subordinated units.

Payments to our general partner and its affiliates Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our intercorporate services agreement, our general partner determines the amount of these expenses and such determinations must be made in good faith under the terms of our partnership agreement. Under our intercorporate services agreement, we will reimburse EEP for expenses incurred by EEP and its affiliates in providing certain operational support and general and administrative services to us. We will also reimburse EEP for any additional out-of-pocket costs and expenses incurred by EEP and its affiliates in providing general and administrative services 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. Please read “—Agreements Governing the Transactions—Intercorporate Services Agreement” below.

Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “Our Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation stage

Liquidation Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties will enter into various agreements with EEP and its affiliates that will effect the transactions described under “Prospectus Summary—The Transactions,” including the vesting of assets in, and the assumption of liabilities by, us and the application of the proceeds of this offering. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with EEP or its affiliates will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. All of the transaction expenses incurred in connection with these transactions will be paid for with the proceeds of this offering.

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Intercorporate services agreement

At the closing of this offering, we will enter into an intercorporate services agreement with EEP pursuant to which EEP will provide us with the following services:

• executive, management, business development, administrative, legal, human resources, records and information management, public affairs, government relations and computer support services;

• accounting and tax planning and compliance services, including preparation of financial statements and income tax returns, as well as audit and treasury services;

• strategic insurance advice, planning and claims management and related support services, and the arrangement of insurance coverage as required;

• capital markets financing and access and cash management and banking services, as well as credit support for our subsidiaries and affiliates on an as-needed basis for projects, transactions or other purposes;

• all other necessary administrative, operational, and technical services required to facilitate our business and affairs; and

• such other services as we may request.

Under the intercorporate services agreement, we will agree to pay costs and expenses incurred by EEP and its affiliates in providing such services to us. EEP will prepare and deliver to us, a written invoice detailing EEP’s consolidated costs for providing such services. We may request that EEP provide additional services for which we will pay costs and expenses incurred by EEP in connection with providing such special additional services. The allocation methodology under which we will reimburse EEP and its affiliates for the provision of general administrative and operational services to Midcoast Operating will not differ from what Midcoast Operating was allocated historically under its prior services agreements with Enbridge and certain of its affiliates that were in effect prior to the intercorporate services agreement. However, EEP has agreed to reduce the allocation of general and administrative expenses to Midcoast Operating by $25 million annually following the closing of this offering. This $25 million annual reduction in general and administrative expenses will continue for the term of the agreement.

Either party may request to modify, add to or discontinue the services provided under the intercorporate services agreement at any time during the term of the agreement. All intellectual property that is conceived of or developed by EEP in the course of providing services to us pursuant to the agreement will be owned by EEP.

Insurance Allocation Agreement.

EEP currently participates, and upon the closing of this offering we will participate, in the comprehensive insurance program that is maintained by Enbridge for it and its subsidiaries. In December 2012, EEP entered into an insurance allocation agreement with Enbridge and another Enbridge subsidiary, and we expect that we will become a party to this agreement upon the closing of this offering. Under this agreement, in the unlikely event that multiple insurable incidents occur that exceed coverage limits within the same insurance period, the total insurance coverage available to Enbridge and its subsidiaries under the insurance program will be allocated among the participating Enbridge entities on an equitable basis.

Financial Support Agreement

In connection with 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

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financial 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 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. 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.

Amended and Restated Limited Partnership Agreement of Midcoast Operating

Upon the closing of this offering, we and EEP will enter into an amended and restated limited partnership agreement of Midcoast Operating. Based on our sole ownership of Midcoast OLP GP, L.L.C., the general partner of Midcoast Operating, we will have the sole responsibility for managing the operations of Midcoast Operating. However, we expect that certain actions of Midcoast Operating will require the unanimous approval of both us and EEP. These actions include the following:

• any reorganization, merger, consolidation or similar transaction;

• any sale or lease of all or substantially all of Midcoast Operating’s assets;

• causing or permitting Midcoast Operating to file an application for bankruptcy; and

• approving any distribution by Midcoast Operating of any assets in kind or the approval of any distribution of any cash or property on a non-pro rata basis.

Under the amended and restated partnership agreement, we and EEP will each have the option to contribute our proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund expansion capital expenditures or other growth projects. To the extent that we or EEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions in exchange for additional interests in Midcoast Operating.

The amended and restated partnership agreement will provide that Midcoast Operating will distribute all distributable cash of Midcoast Operating to us and EEP on a pro rata basis within 45 days of the end of each quarter.

Contribution agreement

At the closing of this offering, we will enter into a contribution, conveyance and assignment agreement, which we refer to as our contribution agreement, with EEP and our general partner under which 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., the general partner of Midcoast Operating, in exchange for our agreement to pay EEP $         million from the proceeds of this offering.

Other Transactions

In the ordinary course of our business, we sell natural gas, NGLs and crude oil to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale. For the year ended December 31, 2012, we had operating revenues of approximately $396.2 million related to these transactions. We also purchase natural gas, NGLs and crude oil from Enbridge and its affiliates for sale to third parties at market prices on the date of purchase. For the year ended December 31, 2012, we paid approximately $287.9 million related to these purchases.

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Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner will adopt a related party transactions policy in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The related party transactions policy will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (1) whether there is an appropriate business justification for the transaction; (2) the benefits that accrue to us as a result of the transaction; (3) the terms available to unrelated third parties entering into similar transactions; (4) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (5) the availability of other sources for comparable products or services; (6) whether it is a single transaction or a series of ongoing, related transactions; and (7) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The related party transactions policy described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

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CONFLICTS OF INTEREST AND DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including EEP and Enbridge and their respective affiliates, on the one hand, and us and our unaffiliated limited partners, on the other hand. The directors and executive officers of our general partner have fiduciary duties to manage our general partner in a manner that they believe is in the best interests of its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner that it believes is in the best interests of our partnership.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our general partner may seek the approval of such resolution from the conflicts committee of the board of directors of our general partner or from our unitholders, but is not required to do so. There is no requirement under our partnership agreement that our general partner seek the approval of the conflicts committee or our unitholders for the resolution of any conflict, and, under our partnership agreement, our general partner may decide to seek such approval or resolve a conflict of interest in any other way permitted by our partnership agreement, as described below, in its sole discretion. The board of directors of our general partner will decide whether to refer the matter to the conflicts committee or to our unitholders on a case-by-case basis. In determining whether to refer a matter to the conflicts committee or to our unitholders for approval, the board of directors of our general partner will consider a variety of factors, including the nature of the conflict, the size and dollar amount involved, the identity of the parties involved and any other factors the board of directors deems relevant in determining whether it will seek approval from the conflicts committee or our unitholders. Whenever the board of directors of our general partner makes a determination to refer or not to refer any potential conflict of interest to the conflicts committee for approval or to seek or not to seek unitholder approval, the general partner is acting in its individual capacity, which means that it may act free of any duty or obligation whatsoever to us or our unitholders and will not be required to act in good faith or pursuant to any other standard or duty imposed by our partnership agreement or under applicable law, other than the implied contractual covenant of good faith and fair dealing.

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

• approved by the conflicts committee, which our partnership agreement defines as “special approval”;

• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from the conflicts committee or our unitholders and our general partner’s board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the

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partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in a manner that is in the best interests of the partnership or that the determination or other action meets the specified standard, for example, a transaction on terms no less favorable to us than those generally being provided to or available from unrelated third parties, or is “fair and reasonable” to us. In taking such action, such person 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. If that person has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement.

It is possible, but we believe it is unlikely, that our general partner would approve a matter that the conflicts committee has previously declined to approve or declined to recommend that the full board of directors approve. If the conflicts committee does not approve or does not recommend that the full board of directors approve a matter that has been presented to it, then, unless the board of directors of our general partner has delegated exclusive authority to the conflicts committee, the board of directors of our general partner may subsequently approve the matter. In such a case, although the matter will not have received “special approval” under our partnership agreement, the board of directors of our general partner could still determine that the resolution of the conflict of interest satisfied another standard under our partnership agreement, for example, that the resolution was on terms no less favorable to us than those generally being provided to or available from unrelated third parties or was fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Please. Please read “Management—Management of Midcoast Energy Partners, L.P.—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others.

Affiliates of our general partner, including EEP and Enbridge and their respective affiliates, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner (or as general partner of another company of which we are a partner or member) or those activities incidental to its ownership of interests in us. However, affiliates of our general partner, including EEP and Enbridge and their respective affiliates, are not prohibited from engaging in other businesses or activities, including those that might compete with us.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner or any of its affiliates, including its executive officers, directors, EEP and Enbridge. 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 such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, EEP, Enbridge and such other persons may compete with us for acquisition opportunities and may own an interest in entities that compete with us.

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Our general partner is allowed to take into account the interests of parties other than us, such as EEP, in resolving conflicts of interest.

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 duties. 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, free of any duty or obligation to us and our unitholders, other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in our partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires, and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner.

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable Delaware 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. Examples of decisions that our general partner may make in its individual capacity include: (1) how to allocate business opportunities among us and its other affiliates; (2) whether to exercise its limited call right; (3) how to exercise its voting rights with respect to the units it owns; (4) whether to sell or otherwise dispose of units or other partnership interests that it owns; (5) whether to elect to reset target distribution levels; (6) whether to consent to any merger or consolidation of the partnership or amendment to our partnership agreement; and (7) whether to refer or not to refer any potential conflict of interest to the conflicts committee for special approval or to seek or not to seek unitholder approval;

• provides that the general partner will have no liability to us or our limited partners for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

• generally provides that in a situation involving a transaction with an affiliate or other conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of another conflict of interest is not approved by our public common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest is either on terms no less favorable to us than those generally being provided to or available from unrelated third parties or is “fair and reasonable” to us, considering the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us, then it will be presumed that in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such decision, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

• provides that 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

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final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the cases 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 unlawful.

By purchasing a common unit, a common unitholder will be deemed to have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

• the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

• the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

• the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

• the negotiation, execution and performance of any contracts, conveyances or other instruments;

• the distribution of our cash;

• the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

• the maintenance of insurance for our benefit and the benefit of our partners;

• the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

• the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;

• the indemnification of any person against liabilities and contingencies to the extent permitted by law;

• the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

• the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in good faith when making decisions on our behalf in its capacity as our general partner, and our partnership agreement further provides that in order for a determination to be made in good faith, our general partner must subjectively believe that the

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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. When our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Please read “Our Partnership Agreement—Voting Rights” for information regarding matters that require unitholder approval.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

• the amount and timing of asset purchases and sales;

• cash expenditures;

• borrowings;

• the issuance of additional units; and

• the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $         million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

• enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

• accelerating the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow working capital funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, or our operating company and its operating subsidiaries.

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We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates, including EEP, for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. Our intercorporate services agreement with EEP also addresses our payment of the costs and expenses incurred by EEP and its affiliates for the provision of services to us. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Intercorporate Services Agreement.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, will not be the result of arm’s-length negotiations.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Our general partner will determine, in good faith, the terms of any arrangements or transactions entered into after the close of this offering. While neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with our general partner and its affiliates will be, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of any duty or liability to us or our unitholders, in determining whether to exercise this right. As a result, a common unitholder may have to sell his common units at an undesirable time or price. Please read “Our Partnership Agreement—Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or our conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of our common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of our common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

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 our conflicts committee 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%) 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.

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.”

Duties of the General Partner

The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate, except for the implied contractual covenant of good faith and fair dealing, the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

As permitted by the Delaware Act, our partnership agreement contains various provisions replacing the fiduciary duties that might otherwise be owed by our general partner with contractual standards governing the

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duties of our general partner and contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has duties to manage our general partner in a manner that is in the best interests of its owners in addition to the best interests of our partnership. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. These provisions enable our general partner to take into consideration the interests of all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to such unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the fiduciary duties imposed on general partners of a limited partnership by the Delaware Act in the absence of partnership agreement provisions to the contrary, the contractual duties of our general partner contained in our partnership agreement that replace the fiduciary duties that would otherwise be imposed by Delaware laws on our general partner and the rights and remedies of our unitholders with respect to these contractual duties:

State law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present unless such transactions were entirely fair to the partnership.

Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and our general partner will not be subject to any other standard under our partnership agreement or applicable law, other than the implied contractual covenant of good faith and fair dealing. If our general partner has the required subjective belief, then the decision or action will be conclusively deemed to be in good faith for all purposes under our partnership agreement. In taking such action, 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. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act free of any duty or obligation to us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. These standards reduce the obligations to which our

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general partner would otherwise be held. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders or that are not approved by our conflicts committee must be: on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). If our general partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. If our general partner does not seek approval from our conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors 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 unlawful.

Rights and remedies of unitholders The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties, if any, or of the partnership agreement.

By purchasing our common units, each common unitholder will be deemed to have agreed to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

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Under our partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons 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 unlawful. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, or the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and therefore unenforceable. Please read “Our Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units represent limited partner interests in us. The holders of our common units, along with the holders of our subordinated units, are entitled to participate in partnership distributions and are entitled to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “Our Partnership Agreement.”

Transfer Agent and Registrar

Duties

             will serve as the registrar and transfer agent for our common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by our unitholders:

• surety bond premiums to replace lost or stolen certificates, or to cover taxes and other governmental charges in connection therewith;

• special charges for services requested by a holder of a common unit; and

• other similar fees or charges.

There will be no charge to our unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their respective stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

• will be deemed to have agreed to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;

• represents and warrants that the transferee has the right, power, authority and capacity to enter into our partnership agreement; and

• gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

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Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

• with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

• with regard to the duties of our general partner, please read “Conflicts of Interest and Duties”;

• with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

• with regard to allocations of taxable income and taxable loss, please read “Material Federal Income Tax Consequences.”

Organization and Duration

Our partnership was organized on May 30, 2013, and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of owning, operating, developing and acquiring natural gas and NGL gathering and transportation systems; natural gas processing and treating facilities and NGL fractionation facilities; natural gas, NGL and condensate logistics and marketing assets; and other midstream assets, our general partner has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of our partnership or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.” For a discussion of our general partner’s right to contribute capital to maintain its 2% general partner interest if we issue additional units, please read “—Issuance of Additional Securities.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters that require the approval of a “unit majority” require:

• during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our general partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

• after the subordination period, the approval of a majority of the outstanding common units.

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In voting their common units and subordinated units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

Issuance of additional units No approval rights.

Amendment of our partnership agreement Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets Unit majority. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership Unit majority. Please read “—Termination and Dissolution.”

Continuation of our business upon dissolution Unit majority. Please read “—Termination and Dissolution.”

Withdrawal of the general partner Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to                     , 2023, in a manner which would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of the general partner Not less than 66 ²/₃% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to                     , 2023. Please read “—Transfer of General Partner Interest.”

Transfer of incentive distribution rights Our general partner may transfer any or all of its incentive distribution rights to an affiliate or another person without a vote of our unitholders. Please read “—Transfer of Incentive Distribution Rights.”

Reset of incentive distribution levels No approval right.

Transfer of ownership interests in our general partner No approval right. Please read “—Transfer of Ownership Interests in Our General Partner.”

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Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right of, by the limited partners as a group:

• to remove or replace our general partner;

• to approve some amendments to our partnership agreement; or

• to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that a limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership, except that the fair value of property that is subject to a liability for which the recourse of creditors is limited is included in the assets of the limited partnership only to the extent that the fair value of that property exceeds that liability. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to it at the time it became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in several states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of our operating company may require compliance with legal requirements in the jurisdictions in which our operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interests in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

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Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests, including partnership interests senior to the common units, for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of our common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of our common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

Upon issuance of additional limited partner interests (other than the issuance of common units upon any exercise by the underwriters of their option to purchase additional common units, the issuance of common units in connection with a reset of the incentive distribution target levels or the issuance of common units upon conversion of outstanding partnership interests), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us 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. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The other holders of our common units will not have preemptive rights to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or our limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited amendments

No amendment may be made that would, among other actions:

• increase the obligations of any limited partner without its consent, unless such increase is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

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• increase the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

The provisions of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon the completion of this offering, our general partner and its affiliates will own approximately     % of the outstanding common units and subordinated units on a combined basis (or     % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us) (excluding common units purchased by directors and officers of our general partner and Enbridge Management under our directed unit program).

No unitholder approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

• a change in our name, the location of our principal office, our registered agent or our registered office;

• the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

• a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees, from in any manner, being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), each as amended, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

• an amendment that our general partner determines to be necessary or appropriate in connection with the authorization or issuance of additional partnership interests;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our partnership agreement;

• any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership or other entity, in connection with our conduct of activities permitted by our partnership agreement;

• a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of such change;

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• mergers with, conveyances to, or conversions into, another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger, conveyance or conversion other than those it receives by way of the merger, conveyance or conversion; or

• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

• do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

• are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

• are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of counsel and unitholder approval

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain such an opinion of counsel.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our general partner or call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our general partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than 90% of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

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

A merger, consolidation or conversion of our partnership requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interest of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

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In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our general partner may, however, mortgage, pledge, hypothecate, or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to our partnership agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction and the partnership interests to be issued by us in such merger do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our partnership agreement. We will dissolve upon:

• the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal followed by approval and admission of a successor;

• the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

• the entry of a decree of judicial dissolution of our partnership; or

• there being no limited partners, unless we are continued without dissolution in accordance with the Delaware Act.

Upon a dissolution under the first clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability of any limited partner; and

• neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

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Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to                     , 2023, without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after                     , 2023, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ written notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest” and “—Transfer of Incentive Distribution Rights.”

Upon voluntary withdrawal of our general partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 ²/₃% of our outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a separate class, and a majority of the outstanding subordinated units, voting as a separate class. The ownership of more than 33 ¹/₃% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own     % of the outstanding common units and subordinated units on a combined basis (or     % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us) (excluding common units purchased by directors and officers of our general partner and Enbridge Management under our directed unit program).

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

• the subordination period will end, and all outstanding subordinated units will immediately and automatically convert into common units on a one-for-one basis;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

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• 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 based on the fair market value of those interests as of the effective date of its removal.

In the event of removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its general partner interest and its incentive distribution rights will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest to (1) an affiliate of our general partner (other than an individual), or (2) another entity as part of the merger or consolidation of our general partner with or into such entity or the transfer by our general partner of all or substantially all of its assets to such entity, our general partner may not transfer all or any part of its general partner interest to another person prior to                     , 2023, without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, EEP and its affiliates may sell or transfer all or part of their membership interest in our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

At any time, our general partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of the unitholders.

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Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Midcoast Holdings, L.L.C., as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group who are notified by our general partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our general partner. Please read “—Withdrawal or Removal of Our General Partner.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days’ written notice.

The purchase price in the event of this purchase is the greater of:

• highest cash price paid by either our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

• 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 date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Federal Income Tax Consequences—Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

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Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, a direct transferee of our general partner and its affiliates or a transferee of such direct transferee who is notified by our general partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units as a single class. Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of our common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as a Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

• our general partner;

• any departing general partner;

• any person who is or was an affiliate of our general partner or any departing general partner;

• any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our subsidiaries, an affiliate of us or our subsidiaries or any entity set forth in the preceding three bullet points;

• any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates, excluding any such person providing, on a fee-for-service basis, trustee, fiduciary of custodial services; and

• any person designated by our general partner because such person’s status, service or relationship expose such person to potential claims or suits relating to our or our subsidiaries’ business and affairs.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to

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us to enable us to effectuate, indemnification. We will purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner and its affiliates for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us. Other than a $25.0 million annual reduction in the total general and administrative expenses that will be allocated to us by EEP under our intercorporate services agreement, the expenses for which we are required to reimburse our general partner are not subject to any caps or other limits. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Intercorporate Services Agreement.”

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for financial reporting purposes on an accrual basis. For fiscal and tax reporting purposes, our fiscal year is the calendar year.

We will mail or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also mail or make available summary financial information within 50 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to him:

• a current list of the name and last known address of each record holder;

• copies of our partnership agreement and our certificate of limited partnership and all amendments thereto; and

• certain information regarding the status of our business and financial condition.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our partnership agreement limits the right to information that a limited partner would otherwise have under Delaware law.

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Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our general partner or any of its affiliates, other than individuals, or their assignees. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

Exclusive Forum

Our partnership agreement will provide that the Court of Chancery of the State of Delaware shall be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Act or (5) asserting a claim against us governed by the internal affairs doctrine. Although we believe this provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against our directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action.

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus and assuming that the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will hold an aggregate of              common units and              subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. All of the common units and subordinated units held by our general partner and its affiliates are subject to lock-up restrictions described below. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

Rule 144

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act (excluding common units purchased by directors and officers of our general partner and Enbridge Management under our directed unit program, which will be subject to the lock-up restrictions described below). None of the directors or officers of our general partner own any common units prior to this offering; however, they may purchase common units through the directed unit program or otherwise. Additionally, any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

• 1% of the total number of common units outstanding, which will equal approximately              common units immediately after this offering; or

• the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

At the closing of this offering, the common units owned by our general partner and its affiliates will be restricted and may not be resold publicly except in compliance with the registration requirements of the Securities Act or Rule 144.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the volume limitations, manner of sale provisions and notice requirements of Rule 144.

Our Partnership Agreement and Registration Rights

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “Our Partnership Agreement—Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates, other than individuals, have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years

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after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.

Lock-up Agreements

We and certain of our affiliates, including EEP, Enbridge Management, our general partner, directors and executive officers of our general partner and directors and officers of Enbridge Management, have agreed that, for a period of 180 days from the date of this prospectus, subject to certain limited exceptions, we and they will not, without the prior written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated, issue or dispose of, as applicable, any of our common units or any securities convertible into or exchangeable for our common units. Please read “Underwriting” for a description of these lock-up provisions.

Registration Statement on Form S-8

We intend to file a registration statement on Form S-8 under the Securities Act following this offering to register all common units reserved for issuance under the LTIP. We expect to file this registration statement as soon as practicable after this offering. Common units covered by the registration statement on Form S-8 will be eligible for sale in the public market, subject to applicable vesting requirements and the terms of applicable lock-up agreements described above and Rule 144, if applicable.

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MATERIAL FEDERAL INCOME TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Midcoast Energy Partners L.P. and our operating subsidiaries.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, entities treated as partnerships for U.S. federal income tax purposes, trusts, nonresident aliens, U.S. expatriates and former citizens or long-term residents of the United States or other unitholders subject to specialized tax treatment, such as banks, insurance companies and other financial institutions, tax-exempt institutions, foreign persons (including, without limitation, controlled foreign corporations, passive foreign investment companies and non-U.S. persons eligible for the benefits of an applicable income tax treaty with the United States), IRAs, real estate investment trusts (REITs) or mutual funds, dealers in securities or currencies, traders in securities, U.S. persons whose “functional currency” is not the U.S. dollar, persons holding their units as part of a “straddle,” “hedge,” “conversion transaction” or other risk reduction transaction, and persons deemed to sell their units under the constructive sale provisions of the Internal Revenue Code. In addition, the discussion only comments to a limited extent on state, local and foreign tax consequences. Accordingly, we encourage each prospective unitholder to consult his own tax advisor in analyzing the state, local and foreign tax consequences particular to him of the ownership or disposition of common units and potential changes in applicable tax laws.

No ruling has been requested from the IRS regarding our characterization as a partnership for tax purposes. Instead, we will rely on opinions of Latham & Watkins LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of federal income tax law and legal conclusions with respect thereto, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Latham & Watkins LLP and are based on the accuracy of the representations made by us.

For the reasons described below, Latham & Watkins LLP has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”) and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

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Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, processing, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Latham & Watkins LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

The IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Latham & Watkins LLP on such matters. It is the opinion of Latham & Watkins LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below that:

• We will be classified as a partnership for federal income tax purposes; and

• Each of our operating subsidiaries will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Latham & Watkins LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Latham & Watkins LLP has relied include:

• Neither we nor any of the operating subsidiaries has elected or will elect to be treated as a corporation; and

• For each taxable year, more than 90% of our gross income has been and will be income of the type that Latham & Watkins LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

We believe that these representations have been true in the past and expect that these representations will continue to be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

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If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income, to the extent of our current and accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Latham & Watkins LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders of Midcoast Energy Partners L.P. will be treated as partners of Midcoast Energy Partners L.P. for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Midcoast Energy Partners L.P. for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gains, losses or deductions would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their tax advisors with respect to the tax consequences to them of holding common units in Midcoast Energy Partners L.P.. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Midcoast Energy Partners L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of taxable income

Subject to the discussion below under “—Tax Consequences of Unit Ownership—Entity-Level Collections” we will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. The income we allocate to unitholders will generally be taxable as ordinary income. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

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A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and/or substantially appreciated “inventory items,” each as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, the unitholder will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (often zero) for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of taxable income to distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2016, 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 with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. Our estimate is based upon many assumptions regarding our business operations, including assumptions as to our revenues, capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct.

For each taxable year, the common units will be allocated certain items of gross income that would otherwise be allocated to either the subordinated units or the new class of common units into which the subordinated units are converted. Specifically, for each taxable year during which the subordinated units or the new class of common units into which the subordinated units are converted are outstanding, items of gross income 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.

The ratio of allocable taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

• gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

• we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of common units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any

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increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner to the extent of the general partner’s “net value” as defined in regulations under Section 752 of the Internal Revenue Code, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on deductibility of losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (1) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (2) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or the unitholder’s salary, active business or other income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on interest deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

• interest on indebtedness properly allocable to property held for investment;

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• our interest expense attributed to portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or (if applicable) qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-level collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of income, gain, loss and deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be generally allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts, as adjusted to take into account the unitholders’ share of nonrecourse debt, and, second, to our general partner.

For each taxable year during which the subordinated units or the new class of common units into which the subordinated units are converted are outstanding, items of gross income 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.

Specified items of our income, gain, loss and deduction will be allocated to account for (1) any difference between the tax basis and fair market value of our assets at the time of this offering and (2) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates (or by a third party) that exists at the time of such contribution, together referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and all of our unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if

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negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

• his relative contributions to us;

• the interests of all the partners in profits and losses;

• the interest of all the partners in cash flow; and

• the rights of all the partners to distributions of capital upon liquidation.

Latham & Watkins LLP is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of short sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

• any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

• any cash distributions received by the unitholder as to those units would be fully taxable; and

• while not entirely free from doubt, all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue relating to partnership interests, Latham & Watkins LLP has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

Alternative minimum tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for

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noncorporate taxpayers is 26% on the first $179,500 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax rates

Beginning on January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 20%. Such rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax, or NIIT, on certain net investment income earned by individuals, estates and trusts applies for taxable years beginning after December 31, 2012. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (1) the unitholder’s net investment income and (2) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income and (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins. Recently, the U.S. Department of the Treasury and the IRS issued proposed Treasury Regulations that provide guidance regarding the NIIT. Although the proposed Treasury Regulations are effective for taxable years beginning after December 31, 2013, taxpayers may rely on the proposed Treasury Regulations for purposes of compliance until the effective date of the final regulations. Prospective unitholders are urged to consult with their tax advisors as to the impact of the NIIT on an investment in our common units.

Section 754 election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS unless there is a constructive termination of the partnership. Please read “—Disposition of Common Units—Constructive Termination.” The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply with respect to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, the inside basis in our assets with respect to a unitholder will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property that is subject to depreciation under Section 168 of the Internal Revenue Code and whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a

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rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” Latham & Watkins LLP is unable to opine as to whether our method for taking into account Section 743 adjustments is sustainable for property subject to depreciation under Section 167 of the Internal Revenue Code or if we use an aggregate approach as described above, as there is no direct or indirect controlling authority addressing the validity of these positions. Moreover, the IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting method and taxable year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain,

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loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Initial tax basis, depreciation and amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (1) this offering will be borne by our general partner and its affiliates, and (2) any other offering will be borne by our general partner and all of our unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods, including bonus depreciation to the extent available, that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and tax basis of our properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of gain or loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of

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the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us that in the aggregate were in excess of cumulative net taxable income for a common unit and, therefore, decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at the U.S. federal income tax rate applicable to long-term capital gains. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations. Both ordinary income and capital gain recognized on a sale of units may be subject to the NIIT in certain circumstances. Please read “—Tax Consequences of Unit Ownership—Tax Rates.”

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract;

in each case, with respect to the partnership interest or substantially identical property.

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Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations between transferors and transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations as there is no direct or indirect controlling authority on this issue. Recently, the U.S. Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Latham & Watkins LLP is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders because the issue has not been finally resolved by the IRS or the courts. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations. A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive termination

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.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets.

Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. In either case, and as stated above under “—Tax Consequences of Unit Ownership—Section 754 Election,” Latham & Watkins LLP has not rendered an opinion with respect to these methods. Moreover, the IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below to a

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limited extent, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, our quarterly distribution to foreign unitholders will be subject to withholding at the highest applicable effective tax rate. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our earnings and profits, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (1) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (2) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the five-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information returns and audit procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Latham & Watkins LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

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The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Additional withholding requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as specially defined in the Internal Revenue Code) and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on interest, dividends and other fixed or determinable annual or periodical gains, profits and income from sources within the United States (“FDAP Income”), or gross proceeds from the sale or other disposition of any property of a type which can produce interest or dividends from sources within the United States (“Gross Proceeds”) paid to a foreign financial institution or to a “non-financial foreign entity” (as specially defined in the Internal Revenue Code), unless (1) the foreign financial institution undertakes certain diligence and reporting, (2) the non-financial foreign entity either certifies it does not have any substantial U.S. owners or furnishes identifying information regarding each substantial U.S. owner or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in clause (1) above, it must enter into an agreement with the U.S. Treasury requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to noncompliant foreign financial institutions and certain other account holders.

These rules generally will apply to payments of FDAP Income made on or after January 1, 2014 and to payments of relevant Gross Proceeds made on or after January 1, 2017. Thus, to the extent we have FDAP Income or Gross Proceeds after these dates that are not treated as effectively connected with a U.S. trade or business (please read “—Tax-Exempt Organizations and Other Investors”), unitholders who are foreign financial institutions or certain other non-US entities may be subject to withholding on distributions they receive from us, or their distributive share of our income, pursuant to the rules described above.

Prospective investors should consult their own tax advisors regarding the potential application of these withholding provisions to their investment in our common units.

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Nominee reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

• the name, address and taxpayer identification number of the beneficial owner and the nominee;

• whether the beneficial owner is:

• a person that is not a U.S. person;

• a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

• a tax-exempt entity;

• the amount and description of units held, acquired or transferred for the beneficial owner; and

• specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from dispositions.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1,500,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

• for which there is, or was, “substantial authority”; or

• as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

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A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation or certain other thresholds are met, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Administrative Matters—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following additional consequences:

• accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Administrative Matters—Accuracy-Related Penalties”;

• for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

• in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

Recent Legislative Developments

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 “—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.

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State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in over 30 states. Most of these states impose an income tax on corporations and other entities, and most of these states also impose a personal income tax on individuals. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states, localities and foreign jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Latham & Watkins LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA, collectively, “Similar Laws.” For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs or annuities established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements, collectively, “Employee Benefit Plans.” Among other things, consideration should be given to:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

• whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

• whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors”; and

• whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an Employee Benefit Plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit Employee Benefit Plans from engaging, either directly or indirectly, in specified transactions involving “plan assets” with parties that, with respect to the Employee Benefit Plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the Employee Benefit Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such Employee Benefit Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The U.S. Department of Labor regulations and Section 3(42) of ERISA provide guidance with respect to whether, in certain circumstances, the assets of an entity in which Employee Benefit Plans acquire equity interests would be deemed “plan assets.” Under these rules, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by the Employee Benefit Plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

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(b) the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by “benefit plan investors,” which is defined to mean that less than 25% of the value of each class of equity interest, disregarding any such interests held by our general partner, its affiliates and some other persons, is held generally by Employee Benefit Plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above. The foregoing discussion of issues arising for employee benefit plan investments under ERISA and the Internal Revenue Code is general in nature and is not intended to be all inclusive, nor should it be construed as legal advice. In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

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UNDERWRITING

Merrill Lynch, Pierce, Fenner & Smith Incorporated is acting as the representative of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement among us and the underwriters, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the number of common units set forth opposite its name below.

Underwriter	Number of Common Units
Merrill Lynch, Pierce, Fenner & Smith                        Incorporated
Total

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of the common units sold under the underwriting agreement if any of these common units are purchased. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the nondefaulting underwriters may be increased or the underwriting agreement may be terminated.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering the common units, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the common units, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officer’s certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Commissions and Discounts

The representative has advised us that the underwriters propose initially to offer the common units to the public at the public offering price set forth on the cover page of this prospectus and to dealers at that price less a concession not in excess of $         per common unit. After the initial offering, the public offering price, concession or any other term of the offering may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their option to purchase additional common units.

	Per Common Unit	Without Option	With Option
Public offering price	$	$	$
Underwriting discount	$	$	$
Proceeds, before expenses, to Midcoast Energy Partners, L.P.	$	$	$

We will also pay to Merrill Lynch, Pierce, Fenner & Smith Incorporated a structuring fee equal to     % of the gross proceeds of this offering for the evaluation, analysis and structuring of our partnership.

The expenses of the offering, not including the underwriting discount, are estimated at $                     million and are payable by us.

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Option to Purchase Additional Common Units

We have granted an option to the underwriters, exercisable for 30 days after the date of this prospectus, to purchase up to              additional common units at the public offering price, less the underwriting discount. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional common units approximately proportionate to that underwriter’s initial amount reflected in the above table. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

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 below 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.

No Sale of Similar Securities

We and certain of our affiliates, including EEP, Enbridge Management, our general partner, directors and executive officers of our general partner and directors and officers of Enbridge Management, have agreed that, for a period of 180 days from the date of this prospectus subject to certain limited exceptions, we and they will not, without the prior written consent of Merrill Lynch, Pierce, Fenner & Smith Incorporated, issue or dispose of, as applicable, any of our common units or any securities convertible into or exchangeable for our common units. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly:

• offer, pledge, sell or contract to sell any common units,

• sell any option or contract to purchase any common units,

• purchase any option or contract to sell any common units,

• grant any option, right or warrant for the sale of any common units,

• lend or otherwise dispose of or transfer any common units,

• request or demand that we file a registration statement related to the common units, or

• enter into any swap or other agreement that transfers, in whole or in part, the economic consequence of ownership of any common units, whether any such swap or transaction is to be settled by delivery of common units or other securities, in cash or otherwise.

This lock-up provision applies to common units and to securities convertible into or exchangeable or exercisable for or repayable with common units. It also applies to common units owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition. In the event that either (x) during the last 17 days of the lock-up period referred to above, we issue an earnings release or material news or a material event relating to us occurs or (y) prior to the expiration of the lock-up period, we announce that we will release earnings results or become aware that material news or a material event will occur during the 16-day period beginning on the last day of the lock-up period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

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New York Stock Exchange Listing

We intend to apply to list our common units on the New York Stock Exchange under the symbol “MEP.” In order to meet the requirements for listing on that exchange, the underwriters have undertaken to sell a minimum number of common units to a minimum number of beneficial owners as required by that exchange.

Before this offering, there has been no public market for our common units. The initial public offering price for the common units will be determined through negotiations between us and the representative. In addition to prevailing market conditions, the factors to be considered in determining the initial public offering price are

• the valuation multiples of publicly traded companies that the representative believe to be comparable to us,

• our financial information,

• the history of, and the prospects for, our partnership and the industry in which we compete,

• an assessment of our management, its past and present operations, and the prospects for, and timing of, our future revenues,

• the present state of our development, and

• the above factors in relation to market values and various valuation measures of other companies engaged in activities similar to ours.

An active trading market for the common units may not develop. It is also possible that after the offering the common units will not trade in the public market at or above the initial public offering price.

The underwriters do not expect to sell more than 5% of the common units in the aggregate to accounts over which they exercise discretionary authority.

Price Stabilization, Short Positions and Penalty Bids

Until the distribution of the common units is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our common units. However, the representative may engage in transactions that stabilize the price of the common units, such as bids or purchases to peg, fix or maintain that price.

In connection with the offering, the underwriters may purchase and sell our common units in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of common units than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional common units described above. The underwriters may close out any covered short position by either exercising their option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the option granted to them. “Naked” short sales are sales in excess of such option. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common units made by the underwriters in the open market prior to the completion of the offering.

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The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representative has repurchased common units sold by or for the account of such underwriter in stabilizing or short covering transactions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of our common units. As a result, the price of our common units may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common units. In addition, neither we nor any of the underwriters make any representation that the representative will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

Electronic Distribution

In connection with the offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail.

FINRA

Because the Financial Industry Regulatory Authority, or FINRA, is expected to view the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Other Relationships

Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us or our affiliates. They have received, or may in the future receive, customary fees and commissions for these transactions. Affiliates of Merrill Lynch, Pierce, Fenner & Smith Incorporated are lenders and/or agents under one or more of EEP’s credit facilities.

In addition, in the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

• to any legal entity which is a qualified investor as defined in the Prospectus Directive;

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• to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

• in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a “recognised collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

(1) if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the CIS Promotion Order) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

(2) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(3) in both cases (1) and (2) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).

Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

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Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in the Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

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VALIDITY OF THE COMMON UNITS

The validity of our common units will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of Midcoast Operating, L.P. as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, included in the prospectus, have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of such firm as experts in auditing and accounting.

The statement of financial position of Midcoast Energy Partners, L.P. as of May 31, 2013, included in this prospectus, has been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of such firm as experts in auditing and accounting.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a website on the internet at www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s website and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

Upon completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at www.                    .com and we make our periodic reports and other information filed with or furnished to the 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.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements and furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

EEP and Enbridge are subject to the information requirements of the Exchange Act, and in accordance therewith files reports and other information with the SEC. You may read EEP’s filings on the SEC’s website and at the public reference room described above or at www.enbridgepartners.com. EEP’s common units trade on the NYSE under the symbol “EEP.” You may read Enbridge’s and Enbridge Management’s filings on the SEC’s website and at the public reference room described above or at www.enbridge.com and www.enbridgemanagement.com, respectively. Enbridge’s common stock trades on the NYSE in the United States and the Toronto Stock Exchange in Canada under the symbol “ENB.” Enbridge Management’s shares trade on the NYSE under the symbol “EEQ.”

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
MIDCOAST ENERGY PARTNERS, L.P.
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
Introduction		F-2
Unaudited Pro Forma Consolidated Statements of Income for the three months ended March 31, 2013		F-4
Unaudited Pro Forma Consolidated Statements of Income for the year ended December 31, 2012		F-5
Unaudited Pro Forma Consolidated Statements of Financial Position as of March 31, 2013		F-6
Notes to the Unaudited Pro Forma Consolidated Financial Statements		F-7
MIDCOAST ENERGY PARTNERS, L.P.
HISTORICAL STATEMENT OF FINANCIAL POSITION
Report of Independent Registered Public Accounting Firm		F-8
Statements of Financial Position as of May 31, 2013		F-9
Notes to Statements of Financial Position		F-10
MIDCOAST OPERATING, L.P. (PREDECESSOR)
HISTORICAL CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm		F-11
Consolidated Statements of Income for the years ended December 31, 2012, 2011 and 2010		F-12
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010		F-13
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010		F-14
Consolidated Statements of Financial Position as of December 31, 2012 and 2011		F-15
Consolidated Statements of Partners’ Capital for the years ended December  31, 2012, 2011 and 2010		F-16
Notes to the Consolidated Financial Statements		F-17
HISTORICAL CONSOLIDATED INTERIM FINANCIAL STATEMENTS
Consolidated Statements of Income for the three month periods ended March  31, 2013 and 2012 (Unaudited)		F-53
Consolidated Statements of Comprehensive Income for the three month periods ended March  31, 2013 and 2012 (Unaudited)		F-54
Consolidated Statements of Cash Flows for the three month periods ended March  31, 2013 and 2012 (Unaudited)		F-55
Consolidated Statements of Financial Position as of March 31, 2013 and 2012 (Unaudited)		F-56
Notes to the Consolidated Financial Statements (Unaudited)		F-57

F-1

MIDCOAST ENERGY PARTNERS, LP

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Introduction

The unaudited pro forma consolidated financial statements of Midcoast Energy Partners, L.P. (the “Partnership”) for the year ended December 31, 2012 and as of and for the three months ended March 31, 2013, are derived from the historical audited and unaudited consolidated financial statements of Midcoast Operating, L.P. (“Midcoast Operating”), our predecessor for accounting purposes (the “Predecessor”). These unaudited pro forma consolidated financial statements have been prepared to reflect the formation, initial public offering (the “Offering”) and related transactions of the Partnership. The unaudited pro forma consolidated financial statements have been prepared on the assumption that the Partnership will be treated as a partnership for federal income tax purposes.

In connection with the closing of the Offering, EEP will contribute a 39% controlling interest in the Predecessor to the Partnership, consisting of a 38.999% limited partner interest and a 100% member interest in Midcoast OLP GP, L.L.C., which owns a 0.001% general partner interest. The transaction will be recorded at historical cost as it is considered to be a reorganization of entities under common control. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of the Offering had taken place on March 31, 2013, in the case of the unaudited pro forma consolidated statement of financial position, and as of January 1, 2012, in the case of the unaudited pro forma consolidated statements of income for the year ended December 31, 2012 and for the three months ended March 31, 2013. The unaudited pro forma consolidated financial statements may not be indicative of the results that actually would have occurred if the Partnership had acquired its 39% controlling interest in Midcoast Operating on the dates indicated or that would be obtained in the future.

The Partnership’s unaudited pro forma consolidated statement of financial position and the unaudited pro forma consolidated statements of income were derived by adjusting the historical audited and unaudited consolidated financial statements of the Predecessor. The pro forma adjustments are based upon currently available information and certain estimates and assumptions. The actual impact of these transactions may differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to those assumptions and are properly applied in the unaudited pro forma consolidated financial statements. The unaudited pro forma consolidated financial statements should be read in conjunction with the accompanying notes and with the historical audited and unaudited consolidated financial statements and related notes set forth elsewhere in this prospectus.

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;

F-2

• 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.

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 pursuant to 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.

F-3

MIDCOAST ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF INCOME

For the three months ended March 31, 2013

			Pro Forma Adjustments
	Predecessor Historical		Related Party Agreements			Offering Related			Pro Forma as Adjusted
	(in millions)
Operating revenue	$	1,370.3	$	—		$	—		$	1,370.3
Operating expenses:
Cost of natural gas and natural gas liquids		1,196.1		—			—			1,196.1
Operating and maintenance		83.4		—			—			83.4
General and administrative		24.5		(6.3	)(a)		—			18.2
Depreciation and amortization		35.2		—			—			35.2
		1,339.2		(6.3	)		—			1,332.9
Operating income		31.1		6.3			—			37.4
Interest expense		—		—			2.8	(b)		2.8
Other income (expense)		0.1		—			—			0.1
Income before income tax expense		31.2		6.3			(2.8	)		34.7
Income tax expense		0.5		—			—			0.5
Net income		30.7		6.3			(2.8	)		34.2
Net income attributable to non-controlling interest in Midcoast Operating, L.P.		—		—			22.6	(c)		22.6
Net income attributable to Midcoast Energy Partners, L.P.	$	30.7	$	6.3		$	(25.4	)	$	11.6
General partner interest in net income attributable to Midcoast Energy Partners, L.P.									$
Limited partners’ 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									$
Weighted average number of limited partner units outstanding (basic and diluted):
Common units
Subordinated units

The accompanying notes are an integral part of the unaudited pro forma consolidated financial statements

F-4

MIDCOAST ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF INCOME

For the year ended December 31, 2012

				Pro Forma Adjustments
	Predecessor Historical			Related Party Agreements			Offering Related			Pro Forma as Adjusted
	(in millions)
Operating revenue	$	5,357.9		$	—		$	—		$	5,357.9
Operating expenses:
Cost of natural gas and natural gas liquids		4,584.1			—			—			4,584.1
Operating and maintenance		362.3			—			—			362.3
General and administrative		105.1			(25.0	)(a)		—			80.1
Depreciation and amortization		135.0			—			—			135.0
		5,186.5			(25.0	)		—			5,161.5
Operating income		171.4			25.0			—			196.4
Interest expense		—			—			11.0	(b)		11.0
Other income (expense)		(0.1	)		—			—			(0.1	)
Income before income tax expense		171.3			25.0			(11.0	)		185.3
Income tax expense		3.8			—			—			3.8
Net income		167.5			25.0			(11.0	)		181.5
Net income attributable to non-controlling interest in Midcoast Operating, L.P.		—			—			117.4	(c)		117.4
Net income attributable to Midcoast Energy Partners, L.P.	$	167.5		$	25.0		$	(128.4	)	$	64.1
General partner interest in net income attributable to Midcoast Energy Partners, L.P.										$
Limited partners’ 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										$
Weighted average number of limited partner units outstanding (basic and diluted):
Common units
Subordinated units

The accompanying notes are an integral part of the unaudited pro forma consolidated financial statements

F-5

MIDCOAST ENERGY PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

As of March 31, 2013

	Predecessor Historical		Pro Forma Adjustments			Pro Forma as Adjusted
			(in millions)
ASSETS
Current assets
Cash and cash equivalents	$	—	$	465.1	(e)	$	—
				350.0	(f)
				(3.8	)(g)
				(811.3	)(g)
Receivables, trade and other		69.0		—			69.0
Due from general partner and affiliates		243.5		—			243.5
Accrued receivables		417.9		—			417.9
Inventory		76.9		—			76.9
Other current assets		27.0		—			27.0
Total current assets		834.3		—			834.3
Property, plant and equipment, net		3,991.1		—			3,991.1
Goodwill		226.5		—			226.5
Intangibles, net		256.0		—			256.0
Equity investment in joint venture		223.3					223.3
Other assets, net		82.7		3.8	(g)		86.5
Total assets		5,613.9		3.8			5,617.7
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Due to general partner and affiliates		56.4		—			56.4
Accounts payable and other		278.5		—			278.5
Accrued purchases		450.3		—			450.3
Property and other taxes payable		9.5		—			9.5
Total current liabilities		794.7		—			794.7
Long-term debt		—		350.0	(f)		350.0
Other long-term liabilities		72.5		—			72.5
Total liabilities		867.2		350.0			1,217.2
Commitments and contingencies
Partners’ capital
Midcoast Operating, L.P. general and limited partners’ capital		4,740.3		(4,740.3	)(d)		—
Total Midcoast Energy Partners, L.P. partners’ capital		—		1,502.5	(d)(e)(g)		1,502.5
Accumulated other comprehensive income		6.4		—			6.4
Total partners’ capital attributable to Midcoast Energy Partners, L.P.		4,746.7		(3,237.8	)		1,508.9
Non-controlling interest in Midcoast Operating, L.P		—		2,891.6	(d)		2,891.6
Total partners’ capital		4,746.7		(346.2	)		4,400.5
Total liabilities and partners’ capital	$	5,613.9	$	3.8		$	5,617.7

The accompanying notes are an integral part of the unaudited pro forma consolidated financial statements

F-6

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

(in millions)

(a) Represents total general and administrative costs allocated to the Partnership, net of a $25.0 million annual reduction, as set forth in the intercorporate services agreement between EEP and Midcoast Energy Partners, L.P. to be entered into at the closing of the Offering.

(b) Includes interest expense for debt outstanding on the Partnership’s revolving credit facility, including upfront commitment fees and standby fees that would have been paid had the Partnership’s revolving credit facility been in place during the periods presented, less capitalized interest related to the construction of Midcoast Operating’s pipelines, plants and related facilities and Midcoast Operating’s joint venture assets.

(c) Represents a 61% non-controlling interest in the net income of Midcoast Operating retained by EEP.

	Three months ended March 31, 2013			Year ended December 31, 2012
Predecessor Net Income, as reported	$	30.7		$	167.5
G&A services cost abatement		6.3			25.0
Pro Forma Predecessor net income		37.0			192.5
Non-controlling interest %		61	%		61	%
Pro forma non-controlling interest adjustment	$	22.6		$	117.4

(d) Represents the elimination of the Predecessor partners’ capital accounts at March 31, 2013, 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, and EEP’s retention of a 61% non-controlling limited partner interest in Midcoast Operating.

(e) Represents the net proceeds we received from our issuance of              common units to the public in connection with this offering, representing a     % limited partner interest in us, estimated as follows:

	March 31, 2013
Gross proceeds from initial public offering	$	500.0
Less: Underwriting discount and structuring fee		(31.9	)
Expenses and costs of initial public offering		(3.0	)
Net proceeds from initial public offering	$	465.1

(f) Represents $350.0 million we intend to borrow under a newly established $             million revolving credit facility, the proceeds of which were applied as set forth in (g) below.

(g) Represents our application of the cash proceeds of the Offering and borrowings under our revolving credit facility, together with adjustments to cash and cash equivalents as follows:

	March 31, 2013
Net proceeds from initial public offering	$	465.1
Proceeds from borrowings under revolving credit facility		350.0
Total cash proceeds from the offering and revolving credit facility		815.1
Payment for debt issuance costs		(3.8	)
Distribution to EEP of proceeds from the offering and borrowings under revolving credit facility		(811.3	)
	$	—

F-7

Report of independent registered public accounting firm

To the Partners of Midcoast Energy Partners, L.P.

In our opinion, the accompanying statement of financial position presents fairly, in all material respects, the financial position of Midcoast Energy Partners, L.P. (the “Partnership”) at May 31, 2013, in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of the Partnership’s management; our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of financial position is free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of financial position, assessing the accounting principles used and significant estimates made by management, and evaluating the overall statement of financial position presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

June 14, 2013

F-8

MIDCOAST ENERGY PARTNERS, L.P.

STATEMENT OF FINANCIAL POSITION

As of May 31, 2013

Assets
Receivables from related parties	$	1,000
Total assets	$	1,000
Partners’ capital
Limited Partner	$	980
General Partner		20
Total partners’ capital	$	1,000

The accompanying notes are an integral part of this statement of financial position.

F-9

NOTES TO STATEMENT OF FINANCIAL POSITION

1. Description of the Business

Midcoast Energy Partners, L.P. (the “Partnership”) is a Delaware limited partnership formed on May 30, 2013. Midcoast Holdings, L.L.C. (the “General Partner”) is a limited liability company also formed on May 30, 2013 to serve as the general partner of the Partnership.

On June 7, 2013, the General Partner contributed $20 to the Partnership in exchange for a 2% general partner interest and Enbridge Energy Partners, L.P. (the “Limited Partner”) contributed $980 to the Partnership in exchange for a 98% limited partner interest. Since the Partnership had not received these contributions as of May 31, 2013, the contributions were reflected as receivables from related parties on the statement of financial position. The Partnership has had no other transactions as of June 13, 2013.

2. Related Party Transactions

Receivables from related parties were as follows:

	May 31, 2013
Limited Partner	$	980
General Partner		20
Total	$	1,000

F-10

Report of Independent Registered Public Accounting Firm

To the Partners of Enbridge Energy Partners, L.P.:

We have audited the accompanying consolidated statements of financial position of Midcoast Operating, L.P. (f/k/a Enbridge Midcoast Energy, L.P.) and its subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of income, of comprehensive income, of partners’ capital and of cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Midcoast Operating, L.P.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Midcoast Operating, L.P. (f/k/a Enbridge Midcoast Energy, L.P.) and its subsidiaries at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

June 14, 2013

F-11

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF INCOME

	Year ended December 31,
	2012			2011		2010
	(in millions)
Operating revenue	$	5,357.9		$	7,828.2	$	6,654.3
Operating expenses:
Cost of natural gas and natural gas liquids		4,584.1			7,066.6		6,052.2
Operating and maintenance		362.3			317.8		248.9
General and administrative		105.1			81.8		63.7
Depreciation and amortization		135.0			142.7		132.5
		5,186.5			7,608.9		6,497.3
Operating income		171.4			219.3		157.0
Interest expense		—			—		—
Other income (expense)		(0.1	)		2.8		3.0
Income before income tax expense		171.3			222.1		160.0
Income tax expense		3.8			2.9		2.6
Net income	$	167.5		$	219.2	$	157.4

The accompanying notes are an integral part of these consolidated financial statements.

F-12

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year ended December 31,
	2012		2011		2010
	(in millions)
Net income	$	167.5	$	219.2	$	157.4
Other comprehensive income, net of tax expense of $0.2, $0.2, and $0.0, respectively		35.8		22.7		5.0
Comprehensive income	$	203.3	$	241.9	$	162.4

The accompanying notes are an integral part of these consolidated financial statements.

F-13

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2012			2011			2010
	(in millions)
Cash provided by operating activities
Net income	$	167.5		$	219.2		$	157.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		135.0			142.7			132.5
Derivative fair value net losses (gains)		(1.2	)		(16.5	)		2.3
Inventory market price adjustments		9.8			3.6			4.1
Other		3.6			9.0			12.8
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other		67.8			(0.6	)		—
Due from general partner and affiliates		4.5			0.4			3.2
Accrued receivables		(68.2	)		178.4			(323.2	)
Inventory		12.0			24.3			(64.4	)
Current and long-term other assets		(4.5	)		(3.1	)		(8.1	)
Due to general partner and affiliates		17.9			13.6			(19.0	)
Accounts payable and other		1.9			(33.6	)		54.3
Environmental liabilities		0.2			—			(0.2	)
Accrued purchases		6.4			(125.5	)		223.0
Property and other taxes payable		—			3.7			(2.3	)
Net cash provided by operating activities		352.7			415.6			172.4
Cash used in investing activities
Additions to property, plant and equipment		(452.6	)		(442.6	)		(288.5	)
Changes in construction payables		0.9			1.1			13.8
Asset acquisitions		—			(30.7	)		(713.3	)
Proceeds from the sale of net assets		9.2			—			4.3
Joint venture contributions		(168.5	)		(10.7	)		(0.4	)
Other		(3.5	)		2.8			—
Net cash used in investing activities		(614.5	)		(480.1	)		(984.1	)
Cash provided by financing activities
Distributions to partners		(302.2	)		(342.4	)		(231.4	)
Net cash contributions from partners		564.0			406.9			1,043.1
Net cash provided by financing activities		261.8			64.5			811.7
Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of year		—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-14

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	As of December 31,
	2012		2011
	(in millions)
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Receivables, trade and other, net of allowance for doubtful accounts of $1.9 in 2012 and $1.5 in 2011		26.2		93.8
Due from general partner and affiliates		263.5		150.7
Accrued receivables		551.2		483.0
Inventory		74.8		96.6
Other current assets		32.5		24.6
		948.2		848.7
Property, plant and equipment, net		3,963.0		3,651.3
Goodwill		226.5		226.5
Intangibles, net		257.2		265.3
Equity investment in joint venture		183.7		10.7
Other assets, net		88.8		132.1
	$	5,667.4	$	5,134.6
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Due to general partner and affiliates	$	41.3	$	22.4
Accounts payable and other		314.5		224.8
Accrued purchases		494.3		482.4
Property and other taxes payable		16.4		16.4
		866.5		746.0
Other long-term liabilities		86.7		139.5
		953.2		885.5
Commitments and contingencies
Partners’ capital
Limited partner interest		4,707.1		4,277.8
General partner interest		—		—
Accumulated other comprehensive income (loss)		7.1		(28.7	)
Total partners’ capital		4,714.2		4,249.1
	$	5,667.4	$	5,134.6

The accompanying notes are an integral part of these consolidated financial statements.

F-15

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	Year ended December 31,
	2012			2011			2010
	(in millions)
General Partner:
Beginning balance	$	—		$	—		$	—
Ending balance		—			—			—
Limited Partner:
Beginning balance		4,277.8			3,994.1			3,025.0
Net income allocation		167.5			219.2			157.4
Net cash capital contributions		564.0			406.9			1,043.1
Distributions		(302.2	)		(342.4	)		(231.4	)
Ending balance		4,707.1			4,277.8			3,994.1
Accumulated other comprehensive income:
Beginning balance		(28.7	)		(51.4	)		(56.4	)
Net realized gains (losses) on changes in fair value of derivative financial instruments reclassified to earnings		(0.1	)		59.3			21.4
Unrealized net gain (loss) on derivative financial instruments		35.9			(36.6	)		(16.4	)
Ending balance		7.1			(28.7	)		(51.4	)
Total partners’ capital at December 31	$	4,714.2		$	4,249.1		$	3,942.7

The accompanying notes are an integral part of these consolidated financial statements.

F-16

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND NATURE OF OPERATIONS

General

Midcoast Operating, L.P., formerly known as Enbridge Midcoast Energy, L.P., together with its consolidated subsidiaries, which are referred to herein as “we,” “us,” “our” and “Midcoast Operating,” is a growth-oriented Delaware limited partnership that is wholly owned by Enbridge Energy Partners, L.P., or EEP. We own and operate a portfolio of assets engaged in the business of gathering, processing and treating natural gas, as well as the transportation and marketing of natural gas, natural gas liquids, or NGLs, and condensate. Our portfolio of natural gas and NGL pipelines, plants and related facilities are geographically concentrated in the Gulf Coast and Mid-Continent regions of the United States, primarily in Texas and Oklahoma. We also own and operate natural gas and NGL logistics and marketing assets that primarily support our gathering, processing and transportation business. We hold our assets in a series of limited partnerships and limited liability companies that we wholly own, either directly or indirectly.

Our capital accounts consist of general partner interest held by Enbridge Midcoast Holdings, L.L.C., a wholly owned subsidiary of EEP, and limited partner interests held directly by EEP. At December 31, 2012 and 2011 our equity interests were distributed as follows:

	2012			2011
Limited partner interests		99.999	%		99.999	%
General partner interests		0.001	%		0.001	%

Enbridge Energy Partners, L.P.

EEP was formed in 1991 by Enbridge Energy Company, Inc., its general partner, an indirect, wholly-owned subsidiary of Enbridge Inc., which we refer to as Enbridge, a leading energy transportation and distribution company located in Calgary, Alberta, Canada. EEP was formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership, which owns the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada.

EEP is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets and, through its ownership interests in us, natural gas gathering, treating, processing, transmission and marketing assets in the United States of America. EEP’s Class A common units are traded on the New York Stock Exchange, or NYSE, under the symbol “EEP.”

Enbridge Energy Management, L.L.C.

Enbridge Energy Management, L.L.C., which we refer to as Enbridge Management, is a Delaware limited liability company that was formed in May 2002. EEP’s general partner, through Enbridge Management’s direct ownership of the voting shares of Enbridge Management, elects all of its directors. Enbridge Management’s listed shares are traded on the NYSE under the symbol “EEQ.” Enbridge Management owns all of a special class of EEP’s limited partner interests and derives all of its earnings from its investment in EEP.

Enbridge Management’s principal activity is managing the business and affairs of EEP pursuant to a delegation of control agreement among EEP’s general partner, Enbridge Management and EEP. The delegation of control agreement provides that Enbridge Management will not amend or propose to amend EEP’s partnership agreement, allow a merger or consolidation involving EEP, allow a sale or exchange of all or substantially all of

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our assets or dissolve or liquidate EEP without the approval of EEP’s general partner. In accordance with its limited liability company agreement, Enbridge Management’s activities are restricted to being a limited partner of EEP and managing its business and affairs.

Enbridge Inc.

Enbridge is the indirect parent of EEP’s general partner, and its common shares are publicly traded on the NYSE in the United States and the Toronto Stock Exchange in Canada under the symbol “ENB”. Enbridge is a leader in energy transportation and distribution in North America, with a focus on crude oil and liquids pipelines, natural gas pipelines, natural gas distribution and renewable energy. At December 31, 2012 and 2011, Enbridge and its consolidated subsidiaries held an effective 21.8% and 23.0% interest in EEP, respectively, through its ownership in Enbridge Management and EEP’s general partner.

Business Segments

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

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.

Our gathering, processing and transportation business primarily consists of our Anadarko system, the East Texas system and the North Texas system, which provide natural gas gathering, processing, transportation and related services predominantly in active producing basins in east and north Texas, as well as the Texas Panhandle and western Oklahoma. At December 31, 2012, our gathering, processing and transportation business included 10 active natural gas treating plants and 20 active natural gas processing plants. In addition, our gathering, processing and transportation business includes approximately 11,400 miles of natural gas gathering and transmission lines and approximately 222 miles of NGL gathering and transportation lines.

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.

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2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Use of Estimates

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, or U.S. GAAP. Our preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingent assets and liabilities. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known.

Principles of Consolidation

The consolidated financial statements include our accounts and those of our wholly and majority-owned subsidiaries on a consolidated basis. All significant intercompany accounts and transactions have been eliminated in consolidation. We consolidate the accounts of entities over which we have a controlling financial interest through our ownership of the general partner or the majority voting interests of the entity. Our 35% ownership interests in Texas Express Pipeline, L.L.C. and Texas Express Gathering, L.L.C. are accounted for under the equity method of accounting as a result of our ability to significantly influence the operating activities of these entities, but insufficient ability to control these activities without the participation of a majority of the other members.

Revenue Recognition and the Estimation of Revenues and Cost of Natural Gas and Natural Gas Liquids

Gathering, Processing and Transportation

We recognize revenue upon delivery of natural gas and NGLs to customers, when services are rendered, pricing is determinable and collectability is reasonably assured. We derive revenue in our gathering, processing and transportation business from the following types of arrangements:

Fee-Based Arrangements. In a fee-based arrangement, we receive a fee per Mcf of natural gas processed or per gallon of NGLs produced. Under this arrangement, we have no direct commodity price exposure. Revenues of our gathering, processing and transportation business that are derived from transmission services consist of reservation fees charged for transportation of natural gas on some of our intrastate pipeline systems. Customers paying these fees typically pay a reservation fee each month to reserve capacity plus a nominal commodity charge based on actual transportation volumes. Reservation fees are required to be paid whether or not the shipper delivers the volumes, thus referred to as a ship-or-pay arrangement. Additional revenues from our intrastate pipelines are derived from the combined sales of natural gas and transportation services.

Commodity-Based Arrangements. Our gathering, processing and transportation business also generates revenue and segment gross margin under other types of service arrangements with customers. These arrangements expose us to commodity price risk, which we mitigate to a substantial degree with the use of derivative financial instruments. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk” for more information about the derivative activities we use to mitigate our exposure to commodity price risk.

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The commodity-based service contracts we have with customers are categorized as follows:

• Percentage-of-Proceeds. In a percentage-of-proceeds arrangement, we receive a negotiated percentage of the natural gas and NGLs we process in the form of residue natural gas, NGLs, condensate and sulfur, which we can sell at market prices and retain the proceeds as our compensation. This type of arrangement exposes us to commodity price risk, as the revenues from percentage-of-proceeds contracts directly correlate with the market prices of the applicable commodities that we receive.

• Percentage-of-Liquids. In a percentage-of liquids arrangement, we receive a negotiated percentage of the NGLs extracted from natural gas that require processing, which we can then sell at market prices and retain the proceeds as our compensation. This contract structure is similar to percentage-of-proceeds arrangements except that we only receive a percentage of the NGLs produced. This type of contract may also require us to provide the customer with a guaranteed NGL recovery percentage regardless of actual NGL production. Since revenues from percentage-of-liquids contracts directly correlate with the market price of NGLs, this type of arrangement also exposes us to commodity price risk.

• Percentage-of-Index. In a percentage-of index arrangement, we purchase raw natural gas at a negotiated percentage of an agreed upon index price. We then resell the natural gas, generally for the index price, and keep the difference as our compensation.

• Keep-Whole/Wellhead Purchase. In a keep-whole/wellhead purchase arrangement, we gather or purchase raw natural gas from the customer. We extract and retain the NGLs produced during processing for our own account, which we then sell at market prices. In instances where we purchase raw natural gas at the wellhead, we may also sell the resulting residue natural gas for our own account at market prices. In those instances when we gather and process raw natural gas for the customer’s account, we generally must return to the customer residue natural gas with an energy content equivalent to the original raw natural gas we received, as measured in British thermal units, or Btu. This type of arrangement has the highest commodity price exposure because costs are dependent on the price of natural gas purchased and our revenues are dependent on the price of NGLs sold. As a result, we benefit from these types of contracts when the value of the NGLs is high relative to the cost of the natural gas and are disadvantaged when the cost of the natural gas is high relative to the value of the NGLs.

Under the terms of each of our commodity-based service contracts, we retain natural gas and NGLs as our compensation for providing these customers with our services. We seek to hedge our commodity price exposure resulting from such compensation by implementing a hedging strategy that targets, as of any particular date, hedging approximately 70% of our commodity price exposure during the first twelve-month period immediately following that date and approximately 50% of our commodity price exposure during the next succeeding twelve-month period. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell the residue gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate. Many of the derivative financial instruments we use do not qualify for hedge accounting. As a result we record the changes in fair value of the derivative instruments that do not qualify for hedge accounting in our operating results. This accounting treatment produces unrealized non-cash, mark-to-market gains and losses in our reported operating results that can be significant during periods when the commodity price environment is volatile.

Logistics and Marketing

Our logistics and marketing business derives a majority of its segment gross margin from purchasing and receiving natural gas, NGLs and other products from our gathering, processing and transportation business

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and from third-party pipeline systems and processing plants and selling and delivering them to wholesale customers, such as distributors, refiners, fractionators, utilities, chemical facilities and power plants. We contract for third-party pipeline capacity under firm and interruptible transportation contracts for which the pipeline capacity depends on volumes of natural gas from our natural gas assets, which provides us with access to several third-party interstate and intrastate pipelines that can be used to transport natural gas and NGLs to primary market hubs where they can be sold to major customers for these products. Our logistics and marketing business also uses owned and leased trucks and specialized trailers and railcars to transport products such as NGLs, condensate and other liquid hydrocarbons to market. In some instances, our margin per unit of volume sold can be higher if the commodity being marketed requires specialized handling, treating, stabilization or other services.

Our logistics and marketing business also derives segment gross margin from the relative difference in natural gas and NGL prices between the contracted index at which the natural gas and NGLs are purchased and the index price at which they are sold, otherwise known as the “basis spread,” which can vary over time or by location, as well as due to local supply and demand factors. Natural gas and NGLs purchased and sold by our logistics and marketing business is primarily priced at a published daily or monthly price index. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated margins result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. We enter into long-term, fixed-price purchase or sales contracts with our customers and generally will enter into offsetting hedge positions under the same or similar terms.

Estimation of Revenue and Cost of Natural Gas and Natural Gas Liquids

For our gathering, processing and transportation business, as well as our logistics and marketing business, we must estimate our current month revenue and cost of natural gas and natural gas liquids to permit the timely preparation of our consolidated financial statements. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data prior to our preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and cost of natural gas and natural gas liquids based on the best available volume and price data for natural gas and natural gas liquids delivered and received, along with a true-up of the prior month’s estimate to equal the prior month’s actual data. As a result, there is one month of estimated data recorded in our operating revenues and cost of natural gas and natural gas liquids for each of the years ended December 31, 2012, 2011 and 2010. We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the consistency of our processes.

Cash and Cash Equivalents

Throughout the periods covered by the financial statements presented herein, EEP has provided cash management services to us through a centralized treasury system. As a result, all of our charges and cost allocations covered by the centralized treasury system were deemed to have been paid by us to EEP, in cash, during the period in which the cost was recorded in the financial statements. In addition, all of our cash receipts were advanced to EEP as they were received. As a result of using EEP’s centralized treasury system, the excess of cash receipts advanced to EEP over the charges and cash allocation is reflected as net cash distributions to partners in the statements of partners’ capital.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable when we determine that we will not collect all or part of an outstanding balance. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.

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Inventory

Inventory includes product inventory and materials and supplies inventory. We record all product inventories at the lower of our cost, as determined on a weighted average basis, or market value. Our product inventory consists of natural gas and liquid hydrocarbons, such as NGLs and condensate. Upon disposition, product inventory is recorded to cost of natural gas and natural gas liquids at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

Materials and supplies inventory is either used during operations and charged to “Operating and maintenance” as incurred, or used for capital projects and new construction, and capitalized to “Property, plant and equipment, net.”

Operational Balancing Agreements and Natural Gas Imbalances

To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of natural gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a natural gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in-kind through the receipt or delivery of natural gas in the future. Natural gas imbalances are recorded as “Accrued receivables” and “Accrued purchases” on our consolidated statements of financial position using the posted index prices, which approximate market rates, or our weighted average cost of natural gas.

Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment

We capitalize expenditures related to property, plant and equipment, subject to a minimum rule, that have a useful life greater than one year for: (1) assets purchased or constructed; (2) existing assets that are replaced, improved or the useful lives have been extended; or (3) all land, regardless of cost. Acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at the weighted average cost of EEP’s debt.

We categorize our capital expenditures as either maintenance or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are necessary 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 the replacement of system components and equipment that is worn, obsolete or completing its useful life. We also include a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems as maintenance capital expenditures. We expect to incur continuing annual maintenance capital expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital expenditures will increase due to the growth of our pipeline systems. We expect to fund maintenance capital expenditures through operating cash flows.

Expansion capital expenditures are those expenditures that increase our asset base, operating capacity or operating income over the long term or increase the useful life of any of our capital assets. Examples of expansion capital expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or

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enhance revenues, and enable us to respond to governmental regulations and developing industry standards. We anticipate funding expansion capital expenditures temporarily through borrowings under our revolving credit facility, with long-term debt and equity funding being obtained when needed and as market conditions allow.

We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the natural gas production in the basins we serve.

We record depreciation using the group method of depreciation, which is commonly used by pipelines, utilities and similar entities. Under the group method upon the disposition of property, plant and equipment, the net book value less net proceeds is typically charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we recognize a gain or loss in our consolidated statements of income for the difference between the cash received and the net book value of the assets sold. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. At regular intervals, we retain the services of independent consultants to assist us with assessing the reasonableness of the useful lives we have established for the property, plant and equipment of our major systems. Based on the results of these assessments we may make modifications to the assumptions we use to determine our depreciation rates.

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

Assessment of Recoverability of Goodwill

Goodwill represents the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is included with both of our reportable segments.

Pursuant to the authoritative accounting provisions for goodwill and other intangible assets, we do not amortize goodwill, but test it for impairment annually based on carrying values as of the end of the second quarter, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may be impaired. In testing goodwill for impairment, we make critical assumptions that include but are not limited to: (1) projections of future financial performance, which include commodity price and volume assumptions, (2) the expected growth rate of our gathering, processing and transportation business and our logistics and marketing business, (3) residual values of the assets; and (4) market weighted average cost of capital. Impairment occurs when the carrying amount of a reporting unit’s goodwill exceeds its implied fair value. We reduce the carrying value of goodwill to its fair value at the time we determine that an impairment has occurred.

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Assessment of Recoverability of Intangibles

Our intangible assets primarily consist of customer contracts for the purchase and sale of natural gas, natural gas supply opportunities and contributions we have made in aid of construction activities that will benefit our operations, as well as workforce contracts and customer relationships. We amortize these assets on a straight-line basis over the weighted average useful lives of the underlying assets, representing the period over which the assets are expected to contribute directly or indirectly to our future cash flows.

We evaluate the carrying value of our intangible assets whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability of intangibles, we compare the carrying value to the undiscounted future cash flows we expect the intangibles or the underlying assets to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangibles and its carrying amount exceeds its fair value, we write the intangibles down to their fair value.

Derivative Financial Instruments

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate, crude oil and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas and natural gas liquids we purchase for processing. In order to manage the risks to owners, we use a variety of derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to create offsetting positions to specific commodity exposures. We do not have any material exposure to movements in foreign exchange rates as virtually all of our revenues and expenses are denominated in United States dollars, or USD. To the extent that a material foreign exchange exposure arises, we intend to hedge such exposure using derivative financial instruments. In accordance with the authoritative accounting guidance, we record all derivative financial instruments to our consolidated statements of financial position at fair market value. We record the fair market value of our derivative financial instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a net basis by counterparty. Derivative balances are shown net of cash collateral received or posted where master netting agreements exist. For those instruments that qualify for hedge accounting under authoritative accounting guidance, the accounting treatment is dependent on the intended use and designation of each instrument. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting to the line item cost of natural gas and natural gas liquids in our consolidated statements of income.

Our formal hedging program provides a control structure and governance for our hedging activities specific to identified risks and time periods, which are subject to the approval and monitoring by the board of directors of Enbridge Management or a committee of senior management of our general partner. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction and we do not use derivative financial instruments for speculative purposes.

Cash flow hedges are derivative financial instruments that qualify for hedge accounting treatment. We enter into cash flow hedges to reduce the variability in cash flows related to forecasted transactions.

Price assumptions we use to value our non-qualifying derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from OTC market makers to find executable bids and offers. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

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At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective, and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

We record the changes in fair value of derivative financial instruments designated and qualifying as effective cash flow hedges as a component of “Accumulated other comprehensive income” until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized immediately in earnings.

Our earnings are also affected by use of the mark-to-market method of accounting as required under U.S. GAAP for derivative financial instruments that do not qualify for hedge accounting. We use derivative financial instruments such as basis swaps and other similar derivative financial instruments to economically hedge market price risks associated with inventories, firm commitments and certain anticipated transactions. However, these derivative financial instruments do not qualify for hedge accounting treatment under authoritative accounting guidance, and as a result we record changes in the fair value of these instruments on the statement of financial position and through earnings rather than deferring them until the firm commitment or anticipated transactions affect earnings. The use of mark-to-market accounting for derivative financial instruments can cause non-cash earnings volatility resulting from changes in the underlying indices, primarily commodity prices. We provide additional information about the derivative activities we use to mitigate our exposure to commodity price risk in Note 10. Derivative Financial Instruments and Hedging Activities in these consolidated financial statements.

Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value to our derivative instruments associated with our commodity activities. We define fair value as an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date.

We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below:

• Level 1—We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments.

• Level 2—We categorize the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument, as Level 2. This category includes both over-the-counter, or OTC, transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies

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derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted prices for assets and liabilities; (b) time value; (c) volatility factors; and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

• Level 3—We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources. (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: (a) non-binding broker quotes, (b) time value, (c) volatility, (d) correlation and (e) extrapolation methods.

We utilize a mid-market pricing convention, or the “market approach,” for valuation as a practical expedient for assigning fair value to our derivative assets and liabilities. Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation, and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities. We present the fair value of our derivative contracts net of cash paid or received pursuant to collateral agreements on a net-by-counterparty basis in our consolidated statements of financial position when we believe a legal right of setoff exists under an enforceable master netting agreement. Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

Income Taxes

We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax, in which we conduct business. Taxes on our net income generally are borne by our owners through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws that apply to entities organized as partnerships by the State of Texas. This tax is computed on our modified gross margin and we have determined the tax to be income taxes as set forth in the authoritative accounting guidance.

We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax liabilities and assets in the period the legislation is enacted.

Pursuant to the authoritative accounting guidance for accounting for uncertainty in income taxes, we recognize the tax effects of any uncertain tax positions as the largest amount that will more likely than not be realized upon ultimate settlement with a taxing authority having full knowledge of the position and all relevant facts. We recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized.

Net income for financial statement purposes may differ significantly from taxable income of our owners as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.

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Commitments, Contingencies and Environmental Liabilities

We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in “Operating and maintenance” expense in our consolidated statements of income and “Other long-term liabilities” in our consolidated statements of financial position at their undiscounted amounts. We always have the potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

Asset Retirement Obligations

Legal obligations exist for a minority of our right-of-way agreements due to requirements or landowner options that compel us to remove pipelines at final abandonment. Sufficient data exists with certain pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions or the estimated economic life of the asset. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets, which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to allow us to reasonably estimate potential settlement dates and methods.

We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis. We collectively refer to asset retirement obligations and conditional asset retirement obligations as AROs. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

We recorded an ARO of $0.4 million for the year ended December 31, 2012, when we recognized abandonment costs associated with assets we acquired through the September 2010 acquisition of the Elk City

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natural gas gathering and processing system. For the year ended December 31, 2011 and 2010, no additional AROs were recorded. We recorded accretion expense of $0.1 million in our consolidated statements of income for the years ended December 31, 2012, 2011 and 2010 for previously recorded asset retirement obligation liabilities.

We do not have any assets that are legally restricted for purposes of settling our ARO at December 31, 2012 and 2011. The following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for each of the years ended December 31, 2012 and 2011:

	2012		2011
	(in millions)
Balance at beginning of period	$	2.1	$	2.0
Additions		0.4		—
Accretion Expense		0.1		0.1
Balance at end of period	$	2.6	$	2.1

3. ACQUISITIONS

We accounted for each of our completed acquisitions using the acquisition method and recorded the identifiable assets acquired and liabilities assumed at their acquisition-date fair values. We have included the results of operations from each of these acquisitions in our operating results from the acquisition date.

2011 Acquisitions

In May 2011, we acquired natural gas pipeline assets that are complementary to our existing East Texas system assets for a final purchase price of $26.7 million in cash.

2010 Acquisitions

Elk City System Acquisition

In September 2010, we acquired 100% ownership of the entities that comprise the Elk City system for $686.1 million in cash, including amounts for working capital. The Elk City system extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle. At the time of the acquisition, the Elk City system consisted of approximately 800 miles of natural gas gathering and transportation pipelines, one treating plant and three cryogenic processing plants with a total capacity of 370 million cubic feet per day, or MMcf/d, and had a combined NGL production capacity of 20,000 Bpd. The acquisition of the Elk City system complements our existing Anadarko system by providing additional processing capacity and expansion capability. We financed the acquisition with funding provided by EEP through capital contributions to us. The results of operations of the Elk City system have been included in our consolidated financial statements within our gathering, processing and transportation business from the September 16, 2010 acquisition date. The Elk City system acquisition did not significantly impact the operating results of our gathering, processing and transportation business for the year ended December 31, 2010.

Other 2010 Acquisitions

In June 2010, we acquired natural gas pipeline assets that are complementary to our existing East Texas system assets for $16.9 million in cash. In October 2010, we acquired a common carrier trucking company for $10.3 million in cash that expanded our existing trucking fleet in order to accommodate the growing supply needs of our United States Gulf Coast customers. Both acquisitions were allocated to “Property, plant and equipment, net” and “Intangibles, net” in our consolidated statement of financial position at fair value.

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4. INVENTORY

Our inventory is comprised of the following:

	December 31,
	2012		2011
	(in millions)
Materials and supplies	$	0.4	$	0.6
Crude oil inventory		10.1		10.3
Natural gas and NGL inventory		64.3		85.7
	$	74.8	$	96.6

Cost of natural gas and natural gas liquids on our consolidated statements of income includes charges totaling $9.8 million, $3.6 million and $4.1 million for the years ended December 31, 2012, 2011 and 2010, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs, to reflect the current market value at the respective balance sheet dates.

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment is comprised of the following:

	Depreciation Rates(1)	December 31,
		2012			2011
		(in millions)
Land	–	$	8.7		$	7.3
Rights-of-way	2.08% – 7.14%		340.3			303.9
Pipelines	0.29% – 6.70%		1,603.8			1,484.4
Pumping equipment, buildings and tanks	1.48% – 6.67%		65.4			52.4
Compressors, meters and other operating equipment	2.01% – 20.00%		1,755.7			1,564.1
Vehicles, office furniture and equipment	2.19% – 33.33%		133.0			129.4
Processing and treating plants	2.18% – 4.00%		489.8			520.2
Construction in progress			402.2			303.9
Total property, plant and equipment			4,798.9			4,365.6
Accumulated depreciation			(835.9	)		(714.3	)
Property, plant and equipment, net		$	3,963.0		$	3,651.3

⁽¹⁾  We have assets included in the above table that are almost fully depreciated, which yield depreciation rates that suggest these assets have significant remaining useful lives, but in fact have little remaining net book value in relation to their expected service lives.

Based on our own internal study, with consideration of a third-party consultant’s report, revised depreciation rates for our Anadarko, East Texas and North Texas systems were implemented effective July 1, 2011. The average remaining service life of these systems was extended from 29 years to 36 years. The predominant factor contributing to the change in service lives was an increase in the estimated remaining reserves in the regions our systems serve, resulting from enhancements in fracturing technologies, which allows producers greater access to unconventional gas. The new remaining service lives result in an approximate $34.0 million annual reduction to depreciation expense, with a reduction of $34.0 million and $17.0 million realized for the years ended December 31, 2012 and 2011, respectively.

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6. GOODWILL

Our goodwill originated from acquisitions by EEP that are fully associated with our gathering, processing and transportation business and our logistics and marketing business. For each of the years ended December 31, 2012 and 2011, the carrying amount of goodwill was $226.5 million consisting of $206.1 million and $20.4 million related to our gathering, processing and transportation business and our logistics and marketing business, respectively.

We test our goodwill for impairment annually primarily by using a discounted cash flow analysis. In addition, we also consider overall market capitalization of our business, cash flow measurement data and other factors. We completed our annual goodwill impairment test using amounts as of June 30, 2012, which did not indicate the existence of impairment to goodwill associated with any of our segments. Even if our estimate for the fair value of our assets had been reduced by 10% in our June 30, 2012 impairment testing, no impairment charge would have resulted. The critical assumptions used in our analysis included the following:

1) A weighted average cost of capital ranging from 7% to 8%;

2) An annual growth rate for our gathering, processing and transportation business and our logistics and marketing business of approximately 1.0% to 3.5%;

3) A long-term capital structure consisting of approximately 50% debt and 50% equity; and

4) A long-term commodity price forecast using recent pricing information.

We did not identify or recognize any impairments to goodwill in connection with our annual testing of goodwill for impairment during the years ended December 31, 2012, 2011 and 2010. We have not observed any further events or circumstances subsequent to our analysis that would, more likely than not, reduce the fair value of our reporting units below the carrying amounts as of December 31, 2012.

7. INTANGIBLES

The following table provides the gross carrying value, accumulated amortization and activity affecting amounts comprising each of our major classes of intangible assets.

	Gross Carrying Amount						Accumulated Amortization
	Natural Gas Intangibles		Other		Intangible Assets, Gross		Natural Gas Intangibles			Other			Accumulated Amortization Gross			Intangible Assets, Net
	(in millions)
December 31, 2010	$	291.0	$	16.1	$	307.1	$	(28.5	)	$	(2.2	)	$	(30.7	)	$	276.4
Additions		—		0.2		0.2		—			—			—			0.2
Dispositions		—		—		—		—			—			—			—
Amortization		—		—		—		(10.8	)		(0.5	)		(11.3	)		(11.3	)
December 31, 2011		291.0		16.3		307.3		(39.3	)		(2.7	)		(42.0	)		265.3
Additions		—		3.5		3.5		—			—			—			3.5
Dispositions		—		—		—		—			—			—			—
Amortization		—		—		—		(10.8	)		(0.8	)		(11.6	)		(11.6	)
December 31, 2012	$	291.0	$	19.8	$	310.8	$	(50.1	)	$	(3.5	)	$	(53.6	)	$	257.2

Natural gas intangibles include customer contracts and natural gas supply opportunities. Our customer contracts are comprised entirely of natural gas purchase and sale agreements associated with our gathering,

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processing and transportation business and our logistics and marketing business. We amortize our customer contracts on a straight-line basis over the weighted average useful life of the underlying reserves at the time of acquisition, which approximate 25 years.

We obtained a portion of the natural gas supply opportunities in conjunction with the acquisition of our North Texas system in 2003. We obtained an additional $189.2 million of natural gas supply opportunities in connection with our September 2010 acquisition of the Elk City system. The value of these intangible assets is derived from growth opportunities present in the Barnett Shale producing zone of North Texas and the Granite Wash reservoir of the Anadarko basin in western Oklahoma and the Texas Panhandle. The natural gas supply opportunities relate entirely to our gathering, processing and transportation business. We are amortizing the natural gas supply opportunities on a straight line basis over the weighted average estimated useful life of the underlying reserves at the time of the acquisition, which approximate 25 to 30 years.

Our other intangible assets are comprised of contributions we made in aid of construction for our gathering, processing and transportation business. In connection with our October 2010 acquisition of a common carrier trucking company, we recognized $4.4 million of additional intangibles related to workforce contracts and customer relationships. We amortize our workforce contracts and customer relationships on a straight line basis over the weighted average estimated useful life of 3 years and the underlying reserves at the time of the acquisition up to 10 years, respectively.

We estimate the annual amortization expense associated with our intangibles to approximate $11.5 million per year until December 31, 2017.

8. RELATED PARTY TRANSACTIONS

Administrative and Workforce Related Services

Enbridge, Enbridge Management and its affiliates provide management and administrative, operational and workforce related services to us. Employees of Enbridge and its affiliates are assigned to work for one or more affiliates of Enbridge, including us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.

We do not directly employ any of the individuals responsible for managing or operating our business, nor do we have any directors. We obtain managerial, administrative and operational services from EEP’s general partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among us, the Partnership, Enbridge Management, and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse EEP’s general partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us.

General and Administrative Service Agreement

EEP’s general partner, Enbridge Management, Enbridge and affiliates of Enbridge provide managerial, administrative, operational and director services to us pursuant to service agreements, and we reimburse them for the costs of those services. Through a general and administrative services agreement among us, EEP’s general partner, Enbridge Management and Enbridge Employee Services, Inc., a subsidiary of the EEP’s general partner, which we refer to as EES, we are charged for the services of employees resident in the United States. The charges related to these service agreements are included in “General and administrative” expenses on our consolidated statements of income. We, EEP, Enbridge Management and EEP’s general partner receive services from EES under a general and administrative services agreement. Under this agreement, EES provides services to us, EEP, Enbridge Management and EEP’s general partner and charges each recipient for services, on a monthly basis, the actual costs that it incurs for those services. EEP’s general partner and Enbridge Management may

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request that EES provide special additional general services for which each, as appropriate, agrees to pay costs and expenses incurred by EES in connection with providing the special additional general services. The types of services provided under the general and administrative services agreement include:

• accounting, tax planning and compliance services, including preparation of financial statements and income tax returns;

• administrative, executive, legal, human resources and computer support services;

• insurance coverage;

• all administrative and operational services required to operate existing systems and any additional systems acquired by us and operated by EES; and

• facilitation of the business and affairs of Enbridge Management and us, including, but not limited to, public and government affairs, engineering, environmental, finance, audit, operations and operational support, safety/compliance and other services.

EES captures all costs that it incurs for providing the services to us by cost center in its financial system. The cost centers are determined to be “Shared Service,” “EEP only” or “Non-Enbridge Energy Partners, L.P.” Shared Service cost centers are used to capture costs that are not specific to a single United States Enbridge entity but are shared among multiple United States Enbridge entities. The costs captured in the cost centers that are specific to us are charged in full to us. The costs captured in cost centers that are outside of our business unit are charged to other Enbridge entities.

The general method used to allocate the Shared Service costs is established through the budgeting process and reimbursed as follows:

• each cost center establishes a budget;

• each cost center manager estimates the amount of time the department spends on us and entities that are not directly affiliated with us;

• costs are accumulated monthly for each cost center;

• the actual costs accumulated monthly by each cost center are allocated to us or entities that are not directly affiliated with us based on the allocation model; and

• we reimburse EES for our share of the allocated costs;

The total amount reimbursed by us, through EEP, for services received pursuant to the general and administrative services agreement for the years ended December 31, 2012, 2011 and 2010 was $208.7 million, $172.4 million and $138.1 million, respectively. These amounts were settled through “Net cash contributions from partners” as reflected on our Consolidated Statements of Partners’ Capital.

Enbridge, Enbridge Management and its affiliates allocated direct workforce costs to us for our construction projects of $6.4 million, $6.0 million and $3.3 million during 2012, 2011 and 2010, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.

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Insurance Allocation Agreement

We participate in the comprehensive insurance program that is maintained by Enbridge for its benefit and the benefit of its subsidiaries. In December 2012, EEP entered into an insurance allocation agreement with Enbridge and another Enbridge subsidiary. Under this agreement, in the unlikely event that multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement EEP has entered into with Enbridge and another Enbridge subsidiary.

Affiliate Revenues and Purchases

We purchase natural gas, NGLs and crude oil from third parties, which subsequently generates operating revenues from sales to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale. Included in our results for the years ended December 31, 2012, 2011 and 2010, are operating revenues of $396.2 million, $345.4 million and $398.1 million, respectively, related to these transactions.

We also purchase natural gas, NGLs and crude oil from Enbridge and its affiliates for sale to third parties at market prices on the date of purchase. Included in our results for the years ended December 31, 2012, 2011 and 2010, are costs for natural gas purchases of $287.9 million, $200.8 million and $242.3 million, respectively, related to these purchases.

Routine purchases and sales with affiliates are settled monthly through EEP’s centralized treasury function at terms that are consistent with third-party transactions. Routine purchases and sales with affiliates that have not yet been settled are included in “Due from general partner and affiliates” and “Due to general partner and affiliates” on our Consolidated Statements of Financial Position.

Allocated Interest

EEP incurs borrowing interest cost on our behalf, which we recognize to the extent we are able to capitalize such costs to our construction related projects. The interest cost we incur is directly offset by the amount of interest we capitalize on outstanding construction projects.

Our interest cost for the years ended December 31, 2012, 2011 and 2010 is detailed below:

	December 31,
	2012			2011			2010
	(in millions)
Interest expense	$	11.9		$	3.3		$	1.9
Interest capitalized		(11.9	)		(3.3	)		(1.9	)
Interest cost incurred	$	—		$	—		$	—
Interest cost paid	$	11.9		$	3.3		$	1.9

Equity Investment in Joint Venture

We have a 35% aggregate interest in the Texas Express NGL system which is comprised of two joint ventures with third parties that together are constructing a 580-mile NGL intrastate transportation pipeline and a related NGL gathering system that is expected to be in service by the third quarter of 2013. Our equity investment in the Texas Express NGL system at December 31, 2012 and 2011 was $183.7 million and $10.7 million, respectively, which is included on our Consolidated Statements of Financial Position in “Equity investment in joint venture.”

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Our logistics and marketing business has made commitments to transport up to 120,000 barrels per day, or bpd, of NGLs on the Texas Express NGL system from 2013 to 2023.

Partners’ Capital Transactions

Our partners capital accounts are comprised of a 99.999% limited partner interest that is owned entirely by EEP and a 0.001% general partner interest that is owned by Enbridge Midcoast Holdings, L.L.C., or EMH, a wholly owned subsidiary of EEP. We paid cash distributions to EEP and EMH totaling $302.2 million, $342.4 million and $231.4 million for the fiscal years ended December 31, 2012, 2011 and 2010, respectively.

EEP also provides us with cash management services through a centralized treasury system. As a result, all of our charges and cost allocations covered by the centralized treasury system were deemed to have been paid by us to EEP, in cash, during the period in which the cost was recorded in the financial statements. In addition, all of our cash receipts were advanced to EEP as they were received. As a result of using EEP’s centralized treasury system, the excess of cash receipts advanced to EEP over the charges and cash allocation is reflected as net cash distributions to partners in the statements of partners’ capital.

Conflicts of Interest

We are a direct subsidiary of EEP who owns all of our limited partner interests and controls our general partner, EMH. As a result, any conflicts of interest that exist between Enbridge Management, EEP’s general partner, Enbridge and EEP would also represent conflicts with us. Enbridge Management makes all decisions relating to the management of EEP’s business and affairs through a delegation of control agreement with EEP’s general partner and through this arrangement also makes all decisions relating to the management of our business and affairs. EEP’s general partner owns the voting shares of Enbridge Management and elects all of its directors. Enbridge, through its wholly owned subsidiary, Enbridge Pipelines, owns all the common stock of EEP’s general partner. Some of the directors and officers of EEP’s general partner are also directors and officers of Enbridge and Enbridge Management and have fiduciary duties to manage the business of Enbridge and Enbridge, Management in a manner that may not be in the best interests of EEP’s unitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, EEP’s general partner, Enbridge, EEP and Midcoast Operating. EEP’s partnership agreement and therefore our partnership agreement and the delegation of control agreement contain provisions that allow Enbridge Management to take into account the interest of all parties in addition to those of EEP’s owners in resolving conflicts of interest, thereby limiting its fiduciary duties to EEP’s owners, as well as provisions that may restrict the remedies available to EEP’s owners for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

9. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to the operating activities of our gathering, processing, and transportation and logistics and marketing businesses, and we are, at times, subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or otherwise, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our gathering, processing and transportation and logistics and marketing businesses. We continue to voluntarily monitor past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.

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As of December 31, 2012 and 2011, we had accrued $0.1 million for both periods in “Other long-term liabilities,” for costs we have incurred primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our natural gas assets and penalties we have been or expect to be assessed.

Insurance Recoveries

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates, which renews in May of each year. The insurance program includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents, excluding costs for fines and penalties. In the unlikely event that multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement EEP has entered into with Enbridge and another Enbridge subsidiary. For further discussion regarding our insurance allocation agreement, refer to Footnote 8. Related Party Transactions.

Natural Gas in Custody

Approximately 40% to 50% of the natural gas volumes handled by our gathering, processing and transportation business are transported for customers on a contractual basis. We purchase the remaining volumes and sell to third parties downstream of the purchase point. At any point in time, the value of our customers’ natural gas in the custody of our gathering, processing and transportation assets is not significant to our operating results, cash flows, or financial position.

Rights-of-Way

As part of our pipeline construction process, we must obtain certain rights-of-way from landowners whose property the pipeline will cross. Rights-of-way that we buy are capitalized as part of “Property, plant and equipment, net” in our Consolidated Statements of Financial Position. Rights-of-way that we lease are expensed. We have recorded expenses of $0.9 million, $0.6 million and $0.6 million for the leased right-of-way agreements for the years ended December 31, 2012, 2011, and 2010, respectively.

Legal and Regulatory Proceedings

We are a participant in various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We are also directly, or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for certain of our expansion projects.

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Future Minimum Commitments

As of December 31, 2012, our future minimum commitments that have remaining non-cancelable terms in excess of one year are as follows:

	2013		2014		2015		2016		2017		Thereafter		Total
	(in millions)
Purchase commitments(1)	$	83.6	$	—	$	—	$	—	$	—	$	—	$	83.6
Other operating leases		14.1		13.6		12.6		12.1		11.2		32.2		95.8
Rights-of-way(2)		0.8		0.6		0.5		0.7		0.5		12.2		15.3
Product purchase obligations(3)		16.1		15.2		9.8		—		—		—		41.1
Transportation/Service contract obligations(4)		35.6		43.4		42.4		39.5		79.0		551.2		791.1
Fractionation agreement obligations(5)		36.1		43.3		43.3		43.3		43.3		219.7		429.0
Total	$	186.3	$	116.1	$	108.6	$	95.6	$	134.0	$	815.3	$	1,455.9

⁽¹⁾  Represents commitments to purchase materials from third-party suppliers in connection with our growth projects.

⁽²⁾  Rights-of-way payments are estimated to approximate $0.5 million to $0.8 million per year for the remaining life of our systems, which has been assumed to be 25 years for purposes of calculating the amount of future minimum commitments beyond 2017.

⁽³⁾  We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at prices approximating market at the time of delivery.

⁽⁴⁾  The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on the Texas Express NGL system and third-party pipelines and storage facilities.

⁽⁵⁾  The fractionation agreement obligations represent the minimum payment amounts for firm fractionation of our NGL supply that we reserve at third party fractionation facilities.

The purchases made under our non-cancelable commitments for the years ended December 31, 2012, 2011 and 2010 were $117.0 million, $98.4 million and $88.9 million, respectively.

10. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with commodity price risks through 2016 in accordance with our risk management policies.

Accounting Treatment

We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market

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participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply the market approach to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value.

In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in cost of natural gas and natural gas liquids for our commodity-based derivatives. Cash flow is only affected to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in cost of natural gas and natural gas liquids for commodity hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation. We provide additional information about the accounting treatment of our derivative activities we use to mitigate our exposure to commodity price risk in Note 2. Summary of Significant Accounting Policies in these consolidated financial statements.

Non-Qualified Hedges

Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in cost of natural gas and natural gas liquids in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.

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The following transaction types do not qualify for hedge accounting and contribute to the volatility of our income and cash flows:

Commodity Price Exposures:

• Transportation—In our logistics and marketing business, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.

• Storage—In our logistics and marketing business, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas is recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas storage activities can create volatility in our earnings.

• Optional Natural Gas Processing Volumes—In our gathering, processing and transportation business, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Our processing facilities provide us with the ability to reject ethane during periods in which it is economic for us to do so. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

• NGL Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. In the second quarter of 2009, we determined that a sub-group of physical NGL sales contracts with terms allowing for economic net settlement did not qualify for the normal purchases and normal sales, or

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NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.

• Natural Gas Forward Contracts—In our logistics and marketing business, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In the first quarter of 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.

• Natural Gas Options—In our gathering, processing and transportation business, we use options to hedge the forecasted commodity exposure of our NGLs and natural gas. Although options can qualify for hedge accounting treatment under authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of NGLs and natural gas until the underlying transactions are settled.

In all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income in cost of natural gas and natural gas liquids.

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net unrealized gains and losses associated with the changes in fair value of our derivative financial instruments:

	December 31,
	2012			2011			2010
	(in millions)
Gathering, processing and transportation segment
Hedge ineffectiveness	$	3.1		$	(5.3	)	$	3.5
Non-qualified hedges		0.6			14.8			(1.0	)
Logistics and marketing segment
Non-qualified hedges		(2.5	)		7.0			(4.8	)
Derivative fair value net gains (losses)	$	1.2		$	16.5		$	(2.3	)

F-39

Derivative Positions

Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:

	December 31,
	2012			2011
	(in millions)
Other current assets	$	275.0		$	153.9
Other assets, net		78.1			122.0
Accounts payable and other		(259.9	)		(168.3	)
Other long-term liabilities		(78.0	)		(131.1	)
	$	15.2		$	(23.5	)

The changes in the net assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of long-term natural gas, NGL and crude oil sales and purchase contracts.

We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $3.6 million as of December 31, 2012 associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the years ended December 31, 2012 and 2011, unrealized commodity hedge losses of $6.3 million and $6.9 million, respectively, were de-designated as a result of the hedges no longer meeting the hedge accounting criteria. We estimate that approximately $4.2 million, representing unrealized net gains from our cash flow hedging activities based on pricing and positions at December 31, 2012, will be reclassified from AOCI to earnings during the next 12 months.

The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).

	December 31,
	2012			2011
	(in millions)
Counterparty Credit Quality*
AAA	$	—		$	(0.2	)
AA		(116.6	)		(98.6	)
A		(150.4	)		(161.2	)
Lower than A		282.2			236.5
	$	15.2		$	(23.5	)

* As determined by nationally-recognized statistical ratings organizations.

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA^®, financial contracts, we have the right to require collateral from our counterparties. We typically include any cash collateral received in the balances listed above, however, as of December 31, 2012 and 2011, we are holding no cash

F-40

collateral on our asset exposures. When we are in a position of posting collateral to cover our counterparties’ exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.

The ISDA^® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA^® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

The ISDA^® agreements, in combination with our master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA^® agreements. These agreements require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

At December 31, 2012 and 2011, we had credit concentrations in the following industry sectors, as presented below:

	December 31,
	2012			2011
	(in millions)
United States financial institutions and investment banking entities	$	(204.7	)	$	(163.8	)
Non-United States financial institutions		(87.4	)		(89.1	)
Integrated Oil Companies		4.5			1.2
Other		302.8			228.2
	$	15.2		$	(23.5	)

Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. A reconciliation between the derivative balances presented at gross values rather than the net amounts we present in our other derivative disclosures, is also provided below.

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Effect of Derivative Instruments on the Consolidated Statements of Financial Position

	Asset Derivatives					Liability Derivatives
		Fair Value at					Fair Value at
	Financial Position Location	December 31,				Financial Position Location	December 31,
		2012		2011			2012			2011
	(in millions)
Derivatives designated as hedging instruments(1)
Commodity contracts	Other current assets	$	16.9	$	6.4	Accounts payable and other	$	(9.9	)	$	(30.5	)
Commodity contracts	Other assets, net		4.5		11.4	Other long-term liabilities		(5.6	)		(25.9	)
			21.4		17.8			(15.5	)		(56.4	)
Derivatives not designated as hedging instruments
Interest Rate Contracts	Other current assets(2)		246.9		134.2	Accounts payable and  other(2)		(246.9	)		(134.2	)
Interest Rate Contracts	Other assets, net(2)		71.6		109.6	Other long-term liabilities(2)		(71.6	)		(109.6	)
Commodity contracts	Other current assets(2)		13.1		19.5	Accounts payable and other(2)		(11.5	)		(14.2	)
Commodity contracts	Other assets, net(2)		12.6		15.0	Other long-term  liabilities(2)		(12.2	)		(10.8	)
Other contracts	Other current assets		14.9		12.2	Accounts payable and other		(8.4	)		(7.7	)
Other contracts	Other assets, net		0.8		1.2	Other long-term liabilities		—			(0.1	)
			359.9		291.7			(350.6	)		(276.6	)
Total derivative instruments		$	381.3	$	309.5		$	(366.1	)	$	(333.0	)

(1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.

(2) Includes both affiliate and third party transactions.

F-42

Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)		Location of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)			Location of Gain (loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)	Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
(in millions )
Year ended December 31, 2012
Commodity contracts	$	41.8	Cost of natural gas and natural gas liquids	$	0.1		Cost of natural gas and natural gas liquids	$	3.1
Total	$	41.8		$	0.1			$	3.1
Year ended December 31, 2011
Commodity contracts	$	17.7	Cost of natural gas and natural gas liquids	$	(59.3	)	Cost of natural gas and natural gas liquids	$	(5.3	)
Total	$	17.7		$	(59.3	)		$	(5.3	)
Year ended December 31, 2010
Commodity contracts	$	7.4	Cost of natural gas and natural gas liquids	$	(21.4	)	Cost of natural gas and natural gas liquids	$	3.5
Total	$	7.4		$	(21.4	)		$	3.5

⁽¹⁾  Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

Effect of Derivative Instruments on Consolidated Statements of Income

		December 31,
		2012			2011		2010
Derivatives Not Designated as Hedging Instruments	Location of Gain or (Loss) Recognized in Earnings	Amount of Gain or (Loss) Recognized in Earnings(1)
		(in millions)
Commodity contracts	Cost of natural gas and natural gas liquids	$	(1.9	)	$	21.8	$	(5.8	)
Total		$	(1.9	)	$	21.8	$	(5.8	)

⁽¹⁾  Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	December 31, 2012								December 31, 2011
	Assets			Liabilities			Total		Assets			Liabilities			Total
	(in millions)
Fair value of derivatives—gross presentation	$	381.3		$	(366.1	)	$	15.2	$	309.5		$	(333.0	)	$	(23.5	)
Effects of netting agreements		(28.2	)		28.2			—		(33.6	)		33.6			—
Fair value of derivatives—net presentation	$	353.1		$	(337.9	)	$	15.2	$	275.9		$	(299.4	)	$	(23.5	)

F-43

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.

	December 31, 2012									December 31, 2011
	Level 1		Level 2			Level 3		Total		Level 1		Level 2			Level 3			Total
								(in millions)
Commodity contracts:
Financial	$	—	$	(7.0	)	$	8.4	$	1.4	$	—	$	(22.3	)	$	(16.8	)	$	(39.1	)
Physical		—		—			7.4		7.4		—		—			5.6			5.6
Commodity options		—		—			6.4		6.4		—		—			10.0			10.0
Total	$	—	$	(7.0	)	$	22.2	$	15.2	$	—	$	(22.3	)	$	(1.2	)	$	(23.5	)

Qualitative Information about Level 3 Fair Value Measurements

Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (natural gas, NGLs, and crude oil) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would decrease the fair value of the positions.

F-44

Quantitative Information About Level 3 Fair Value Measurements

	Fair Value at December  31, 2012(2)					Range(1)
Contract Type				Valuation Technique	Unobservable Input	Lowest			Highest			Weighted Average			Units
	(in millions)
Commodity Contracts—Financial
Natural Gas	$	8.8		Market Approach	Forward Gas Price		3.21			4.31			3.54		MMBtu
Crude Oil	$	—		Market Approach	Forward Crude Price		—			—			—		Bbl
NGLs	$	(0.4	)	Market Approach	Forward NGL Price		0.25			2.21			1.40		Gal
Commodity Contracts—Physical
Natural Gas	$	1.7		Market Approach	Forward Gas Price		3.19			4.58			3.73		MMBtu
Crude Oil	$	2.6		Market Approach	Forward Crude Price		65.22			116.56			94.31		Bbl
NGLs	$	3.1		Market Approach	Forward NGL Price		0.00			2.22			0.61		Gal
Commodity Options
Natural Gas, Crude and NGLs	$	6.4		Option Model	Option Volatility		29	%		104	%		40	%
Total Fair Value	$	22.2

⁽¹⁾  Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs, dollars per barrel, or Bbl, for Crude Oil.

⁽²⁾  Fair values are presented in millions and include credit valuation adjustments of approximately $0.1 million of losses.

The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2012 to December 31, 2012. No transfers of assets between any of the Levels occurred during the period.

	Commodity Financial Contracts			Commodity Physical Contracts			Commodity Options			Total
	(in millions)
Beginning balance as of January 1, 2012	$	(16.8	)	$	5.6		$	10.0		$	(1.2	)
Transfers in (out) of Level 3(1)		—			—			—			—
Gains or losses
Included in earnings (or changes in net assets)		1.1			30.5			10.2			41.8
Included in other comprehensive income		37.5			—			(0.2	)		37.3
Purchases, issuances, sales and settlements
Purchases		—			—			3.4			3.4
Settlements(2)		(13.4	)		(28.7	)		(17.0	)		(59.1	)
Ending balance as of December 31, 2012	$	8.4		$	7.4		$	6.4		$	22.2
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	$	10.5		$	6.4		$	4.4		$	21.3

⁽¹⁾  Our policy is to recognize transfers as of the last day of the reporting period.

⁽²⁾  Settlements represent the realized portion of forward contracts.

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Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair value of expected cash flows of our outstanding commodity based swaps and physical contracts at December 31, 2012 and 2011.

	At December 31, 2012													At December 31, 2011
				Wtd. Average Price(2)					Fair Value(3)					Fair Value(3)
	Commodity	Notional(1)		Receive		Pay			Asset		Liability			Asset		Liability
Portion of contracts maturing in 2013
Swaps
Receive variable/pay fixed	Natural Gas		2,628,011	$	3.39	$	(3.43	)	$	0.2	$	(0.3	)	$	—	$	(0.1	)
	NGL		120,000	$	85.24	$	(73.16	)	$	1.4	$	—		$	—	$	—
	Crude Oil		556,330	$	93.18	$	(99.90	)	$	0.2	$	(3.9	)	$	—	$	—
Receive fixed/pay variable	Natural Gas		5,487,300	$	4.84	$	(3.43	)	$	7.8	$	—		$	5.9	$	—
	NGL		2,728,135	$	55.46	$	(55.67	)	$	9.3	$	(9.9	)	$	0.5	$	(8.7	)
	Crude Oil		1,732,935	$	91.75	$	(93.20	)	$	6.3	$	(8.9	)	$	2.1	$	(9.9	)
Receive variable/pay variable	Natural Gas		48,477,500	$	3.45	$	(3.43	)	$	1.2	$	(0.2	)	$	0.8	$	(0.1	)
Physical Contracts
Receive variable/pay fixed	NGL		1,009,246	$	33.13	$	(33.34	)	$	0.6	$	(0.8	)	$	—	$	—
	Crude Oil		173,774	$	91.95	$	(92.23	)	$	0.4	$	(0.4	)	$	—	$	—
Receive fixed/pay variable	NGL		2,132,141	$	26.96	$	(26.76	)	$	2.6	$	(2.2	)	$	—	$	—
	Crude Oil		284,774	$	89.55	$	(92.29	)	$	0.3	$	(1.0	)	$	—	$	—
Receive variable/pay variable	Natural Gas		26,152,942	$	3.48	$	(3.45	)	$	0.9	$	—		$	0.5	$	—
	NGL		6,399,658	$	32.49	$	(32.03	)	$	5.2	$	(2.3	)	$	0.4	$	(0.1	)
	Crude Oil		1,106,574	$	95.12	$	(92.04	)	$	6.4	$	(3.0	)	$	—	$	—
Portion of contracts maturing in 2014
Swaps
Receive variable/pay fixed	Natural Gas		21,870	$	3.95	$	(5.22	)	$	—	$	—		$	—	$	—
	Crude Oil		506,255	$	92.16	$	(101.95	)	$	—	$	(4.9	)	$	—	$	—
Receive fixed/pay variable	Natural Gas		2,346,900	$	4.02	$	(3.95	)	$	0.2	$	—		$	—	$	—
	NGL		801,175	$	63.75	$	(66.00	)	$	0.9	$	(2.7	)	$	0.8	$	(1.9	)
	Crude Oil		1,301,955	$	94.21	$	(92.16	)	$	5.4	$	(2.8	)	$	0.3	$	(3.1	)
Receive variable/pay variable	Natural Gas		7,212,500	$	3.99	$	(3.98	)	$	0.1	$	(0.1	)	$	0.1	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		10,556,275	$	4.02	$	(3.97	)	$	0.5	$	—		$	0.1	$	—
	NGL		3,600,000	$	12.40	$	(12.40	)	$	—	$	—		$	—	$	—
Portion of contracts maturing in 2015
Swaps
Receive variable/pay fixed	Crude Oil		515,015	$	90.01	$	(100.93	)	$	—	$	(5.6	)	$	—	$	—
Receive fixed/pay variable	Gas Liquid		109,500	$	88.36	$	(84.31	)	$	0.7	$	(0.2	)	$	0.7	$	(0.2	)
	Crude Oil		865,415	$	97.72	$	(90.01	)	$	6.8	$	(0.2	)	$	1.1	$	(0.4	)
Physical Contracts
Receive variable/pay variable	Natural Gas		7,838,425	$	4.28	$	(4.23	)	$	0.4	$	—		$	0.1	$	—
Portion of contracts maturing in 2016
Swaps
Receive fixed/pay variable	Crude Oil		45,750	$	99.31	$	(88.10	)	$	0.5	$	—		$	0.4	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		783,240	$	4.53	$	(4.42	)	$	0.1	$	—		$	0.1	$	—

⁽¹⁾  Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbls.

⁽²⁾  Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil.

⁽³⁾  The fair value is determined based on quoted market prices at December 31, 2012 and 2011, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses and $0.1 million of gains at December 31, 2012 and 2011, respectively.

F-46

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at December 31, 2012 and 2011.

	At December 31, 2012												At December 31, 2011
	Commodity		Notional(1)		Strike Price(2)		Market Price(2)		Fair Value(3)				Fair Value(3)
									Asset		Liability		Asset		Liability
Portion of option contracts maturing in 2013
Puts (purchased)		Natural Gas		1,642,500	$	4.18	$	3.41	$	1.4	$	—	$	1.2	$	—
		NGL		457,000	$	32.29	$	27.87	$	3.7	$	—	$	0.9	$	—
Portion of option contracts maturing in 2014
Puts (purchased)		NGL		127,750	$	66.39	$	70.78	$	1.3	$	—	$	—	$	—

⁽¹⁾  Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbls.

⁽²⁾  Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.

⁽³⁾  The fair value is determined based on quoted market prices at December 31, 2012 and 2011, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.1 million of losses at December 31, 2011.

Fair Value Measurements of Interest Rate Derivatives

We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.

								Fair Value December 31,
Date of Maturity & Contract Type(1)	Accounting Treatment		Notional		Average Fixed  Rate(2)			2012			2011
					(dollars in millions)
Contracts maturing in 2013
Interest Rate Swaps-Pay Fixed		Non-qualifying	$	800		3.24	%	$	(22.6	)	$	(42.2	)
Interest Rate Swaps-Pay Float		Non-qualifying	$	800		3.24	%	$	22.6		$	42.2
Contracts maturing in 2014
Interest Rate Swaps-Pay Fixed		Non-qualifying	$	200		0.56	%	$	(0.6	)	$	0.2
Interest Rate Swaps-Pay Float		Non-qualifying	$	200		0.56	%	$	0.6		$	(0.2	)
Contracts maturing in 2015
Interest Rate Swaps-Pay Fixed		Non-qualifying	$	300		2.43	%	$	(6.7	)	$	(4.8	)
Interest Rate Swaps-Pay Float		Non-qualifying	$	300		2.43	%	$	6.7		$	4.8
Contracts maturing in 2017
Interest Rate Swaps-Pay Fixed		Non-qualifying	$	500		2.21	%	$	(16.0	)	$	(5.8	)
Interest Rate Swaps-Pay Float		Non-qualifying	$	500		2.21	%	$	16.0		$	5.8
Contracts maturing in 2018
Interest Rate Swaps-Pay Fixed		Non-qualifying	$	500		2.08	%	$	(1.8	)	$	—
Interest Rate Swaps-Pay Float		Non-qualifying	$	500		2.08	%	$	1.8		$	—
Contracts settling prior to maturity
2012-Pre-issuance Hedges		Non-qualifying	$	1,200		4.56	%	$	—		$	—
2013-Pre-issuance Hedges		Non-qualifying	$	1,000		3.98	%	$	—		$	—
2014-Pre-issuance Hedges		Non-qualifying	$	1,500		3.15	%	$	—		$	—
2016-Pre-issuance Hedges		Non-qualifying	$	500		2.85	%	$	—		$	—

⁽¹⁾  Includes both affiliate and third party transactions.

⁽²⁾  Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.

F-47

11. INCOME TAXES

We are not a taxable entity for United States federal income tax purposes, or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our owners through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws that apply to entities organized as partnerships by the State of Texas that are based upon many but not all items included in net income. We report these taxes as income taxes as set forth in the authoritative accounting guidance.

Our income tax expense is $3.8 million, $2.9 million and $2.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. The Texas state income tax rate was 0.5% for the years ended December 31, 2012, 2011 and 2010. Our income tax expense represents effective tax rates as applied to pretax book income of 2.1%, 1.3% and 1.7% for December 31, 2012, 2011 and 2010, respectively. The effective tax rate for the Partnership is calculated by dividing the income tax expense by the pretax net book income or loss. The income base for calculating income tax expense is modified gross margin for Texas.

At December 31, 2012 and 2011, we have included a current income tax payable of $3.7 million and $2.8 million in “Property and other taxes payable,” respectively. In addition, at December 31, 2012 and December 31, 2011, we have included a deferred income tax liability of $3.0 million and $2.8 million, respectively, in “Other long-term liabilities,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

For the years ended December 31, 2012, 2011 and 2010, we paid $2.8 million, $2.5 million and $3.1 million in income taxes, respectively.

We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. The impact of changes in tax legislation on deferred income tax liabilities and assets is recorded in the period of enactment. The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:

	December 31,
	2012			2011
	(in millions)
Net book basis of assets in excess of tax basis	$	(3.0	)	$	(3.0	)
Net book losses on derivatives not recognized for tax purposes		—			0.2
Net deferred tax liability	$	(3.0	)	$	(2.8	)

Our tax years are generally open to examination by the Internal Revenue Service and state revenue authorities for calendar years ended December 2011, 2010, and 2009.

Accounting for Uncertainty in Income Taxes

For the years ended December 31, 2012, 2011 and 2010, respectively, we have not recorded any amounts for uncertain tax positions.

12. SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of executive management of Enbridge Management, in deciding how resources are allocated and performance is assessed.

F-48

Each of our reportable segments is a business unit that offers different services and products that are managed separately, since each business segment requires different operating strategies. We conduct our business through two distinct reporting segments: gathering, processing and transportation and logistics and marketing.

The following tables present certain financial information relating to our business segments and corporate activities as of and for the year ended December 31, 2012:

	December 31, 2012
	Gathering, processing and transportation		Logistics and marketing			Corporate(1)			Total
	(in millions)
Total revenue	$	2,716.9	$	4,640.8		$	—		$	7,357.7
Less: Intersegment revenue		1,898.9		100.9			—			1,999.8
Operating revenue		818.0		4,539.9			—			5,357.9
Cost of natural gas and natural gas liquids		131.2		4,452.9			—			4,584.1
Segment gross margin		686.8		87.0			—			773.8
Operating and maintenance		281.5		80.8			—			362.3
General and administrative		85.8		19.1			0.2			105.1
Depreciation and amortization		128.0		7.0			—			135.0
		495.3		106.9			0.2			602.4
Operating income (loss)		191.5		(19.9	)		(0.2	)		171.4
Other income (expense)		—		—			(0.1	)		(0.1	)
Income (loss) before income tax expense		191.5		(19.9	)		(0.3	)		171.3
Income tax expense		—		—			3.8			3.8
Net income (loss)	$	191.5	$	(19.9	)	$	(4.1	)	$	167.5
Total assets(2)	$	4,461.5	$	971.2		$	234.7		$	5,667.4
Capital expenditures (excluding acquisitions)	$	396.0	$	56.8		$	—		$	452.8

⁽¹⁾  Corporate consists of income taxes, which are not allocated to the business segments.

⁽²⁾  Total assets for our gathering, processing and transportation business includes our long-term equity investment in the Texas Express NGL system.

F-49

	December 31, 2011
	Gathering, processing and transportation		Logistics and marketing		Corporate(1)			Total
	(in millions)
Total revenue	$	3,539.0	$	6,984.4	$	—		$	10,523.4
Less: Intersegment revenue		2,624.8		70.4		—			2,695.2
Operating revenue		914.2		6,914.0		—			7,828.2
Cost of natural gas and natural gas liquids		271.1		6,795.5		—			7,066.6
Segment gross margin		643.1		118.5		—			761.6
Operating and maintenance		241.0		76.8		—			317.8
General and administrative		71.6		10.1		0.1			81.8
Depreciation and amortization		135.2		7.5		—			142.7
		447.8		94.4		0.1			542.3
Operating income (loss)		195.3		24.1		(0.1	)		219.3
Other income (expense)		—		—		2.8			2.8
Income (loss) before income tax expense		195.3		24.1		2.7			222.1
Income tax expense		—		—		2.9			2.9
Net income (loss)	$	195.3	$	24.1	$	(0.2	)	$	219.2
Total assets(2)	$	4,018.7	$	881.7	$	234.2		$	5,134.6
Capital expenditures (excluding acquisitions)	$	376.6	$	66.0	$	—		$	442.6

⁽¹⁾  Corporate consists of income taxes, which are not allocated to the business segments.

⁽²⁾  Total assets for our gathering, processing and transportation business includes our long-term equity investment in the Texas Express NGL system.

	December 31, 2010
	Gathering, processing and transportation		Logistics and marketing		Corporate(1)			Total
	(in millions)
Total revenue	$	2,986.2	$	6,096.3	$	—		$	9,082.5
Less: Intersegment revenue		2,387.7		40.5		—			2,428.2
Operating revenue		598.5		6,055.8		—			6,654.3
Cost of natural gas and natural gas liquids		78.3		5,973.9		—			6,052.2
Segment gross margin		520.2		81.9		—			602.1
Operating and maintenance		191.4		57.5		—			248.9
General and administrative		52.1		11.2		0.4			63.7
Depreciation and amortization		128.2		4.3		—			132.5
		371.7		73.0		0.4			445.1
Operating income (loss)		148.5		8.9		(0.4	)		157.0
Other income (expense)		—		—		3.0			3.0
Income (loss) before income tax expense		148.5		8.9		2.6			160.0
Income tax expense		—		—		2.6			2.6
Net income (loss)	$	148.5	$	8.9	$	—		$	157.4
Total assets	$	3,825.7	$	873.6	$	103.3		$	4,802.6
Capital expenditures (excluding acquisitions)	$	282.0	$	6.4	$	—		$	288.4

⁽¹⁾  Corporate consists of income taxes, which are not allocated to the business segments.

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13. SUBSEQUENT EVENTS

Distribution to Partners

On January 30, 2013, the board of directors of Enbridge Management declared a distribution payable to our partners on February 14, 2013. We distributed cash to our partners of $60.7 million on February 14, 2013.

On April 30, 2013, the board of directors of Enbridge Management declared a distribution payable to our partners on May 15, 2013. We distributed cash to our partners of $58.9 million on May 15, 2013.

14. SUPPLEMENTAL CASH FLOWS INFORMATION

The following table provides supplemental information for the item labeled “Other” in the “Cash from operating activities” section our consolidated statements of cash flows.

	December 31,
	2012			2011			2010
	(in millions)
Amortization of put option premiums	$	3.6		$	8.5		$	11.0
Deferred income taxes		0.1			0.2			(0.1	)
Allowance for interest used during construction		(4.5	)		—			—
Allowance for doubtful accounts		(0.2	)		0.4			0.2
Gain on sale of CO2 plant		—			(1.5	)		—
Write-down of project costs		4.3			—			—
Other		0.3			1.4			1.7
	$	3.6		$	9.0		$	12.8

15. RECENT ACCOUNTING PRONOUNCEMENTS

Accounting Standards Update—Balance Sheet Offsetting

In December 2011, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities, or ASU 2011-11, as part of the FASB’s joint project with the IASB, which requires an entity to disclose information about financial instruments and derivative financial instruments that have been offset within the balance sheet, or are subject to a master netting arrangement or similar agreement, regardless of whether they have been offset within the balance sheet. In January 2013, the FASB issued Accounting Standards Update No. 2013-01 to clarify the scope of transactions subject to the disclosure provisions of ASU 2011-11 include derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with specific criteria established under U.S. GAAP, or that are subject to a master netting arrangement or similar agreement. The objectives of the standards are to allow financial statement users to understand the effect that offsetting of financial instruments and derivative financial instruments have on an entity’s financial position. Both standards are effective for interim and annual reporting periods beginning on or after January 1, 2013, with required disclosures presented retrospectively for all comparative period presented. The adoption of this pronouncement has not had a material impact on our consolidated financial statements.

F-51

Accounting Standards Update—Accumulated Other Comprehensive Income

In February 2013, the FASB issued Accounting Standards No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, or ASU 2013-02, which requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component, but does not change the current requirements for reporting net income or other comprehensive income in financial statements. ASU 2013-02 requires presentation of significant amounts reclassified out of accumulated other comprehensive income into earnings by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The standard is effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. The adoption of this pronouncement has not had a material impact on our financial statements.

Accounting Standards Update—Liabilities

In February 2013, the FASB issued Accounting Standards No. 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, or ASU 2013-04. The provisions of ASU 2013-04 require measurement of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of (1) the amount the reporting entity agreed to pay on the basis of its arrangement among co-obligors and (2) any additional amount the reporting entity expects to pay on behalf of its co-obligors. Additionally, ASU 2013-04 requires disclosure of the nature and amount of the obligation as well as information about such obligations. The provisions of ASU 2013-04 are effective for fiscal years beginning after December 15, 2013, and interim periods within those years and should be applied retrospectively to all prior periods presented, with early adoption permitted. We do not expect to early adopt the provisions of this standard, nor do we expect our adoption to have a material effect on our financial statements.

F-52

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF INCOME

	Three months ended March 31,
	2013		2012
	(unaudited; in millions)
Operating revenue	$	1,370.3	$	1,495.9
Operating expenses:
Cost of natural gas and natural gas liquids		1,196.1		1,306.2
Operating and maintenance		83.4		86.3
General and administrative		24.5		32.4
Depreciation and amortization		35.2		33.1
		1,339.2		1,458.0
Operating income		31.1		37.9
Interest expense		—		—
Other income (expense)		0.1		(0.1	)
Income before income tax expense		31.2		37.8
Income tax expense		0.5		0.6
Net income	$	30.7	$	37.2

The accompanying notes are an integral part of these consolidated financial statements.

F-53

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended March 31,
	2013			2012
	(unaudited; in millions)
Net income	$	30.7		$	37.2
Other comprehensive income (loss)		(0.7	)		(9.5	)
Comprehensive income	$	30.0		$	27.7

The accompanying notes are an integral part of these consolidated financial statements.

F-54

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended March 31,
	2013			2012
	(unaudited; in millions)
Cash provided by operating activities
Net income	$	30.7		$	37.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		35.2			33.1
Derivative fair value net losses (gains)		1.5			(1.9	)
Inventory market price adjustments		0.8			2.4
Other		(2.2	)		0.6
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other		(42.8	)		19.0
Due from general partner and affiliates		7.5			6.8
Accrued receivables		133.3			73.6
Inventory		(2.9	)		21.8
Current and long-term other assets		(1.7	)		2.1
Due to general partner and affiliates		16.5			54.3
Accounts payable and other		(22.6	)		20.4
Accrued purchases		(37.1	)		(119.6	)
Property and other taxes payable		(6.9	)		(7.5	)
Net cash provided by operating activities		109.3			142.3
Cash used in investing activities
Additions to property, plant and equipment		(70.9	)		(116.7	)
Changes in construction payables		(7.1	)		3.2
Asset acquisitions		(0.9	)		—
Proceeds from the sale of net assets		5.0			—
Joint venture contributions		(36.8	)		(27.6	)
Other		(1.1	)		—
Net cash used in investing activities		(111.8	)		(141.1	)
Cash provided by financing activities
Distributions to partners		(60.7	)		(64.0	)
Contributions from partners		63.2			62.8
Net cash provided by (used in) financing activities		2.5			(1.2	)
Net increase (decrease) in cash and cash equivalents		—			—
Cash and cash equivalents at beginning of year		—			—
Cash and cash equivalents at end of period	$	—		$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-55

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	Supplemental Pro Forma As of March 31, 2013		As of March 31, 2013		As of December 31, 2012
	(unaudited; in millions)
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—	$	—
Receivables, trade and other, net of allowance for doubtful accounts of $1.9 in 2013 and $1.9 in 2012		69.0		69.0		26.2
Due from general partner and affiliates		243.5		243.5		263.5
Accrued receivables		417.9		417.9		551.2
Inventory		76.9		76.9		74.8
Other current assets		27.0		27.0		32.5
		834.3		834.3		948.2
Property, plant and equipment, net		3,991.1		3,991.1		3,963.0
Goodwill		226.5		226.5		226.5
Intangibles, net		256.0		256.0		257.2
Equity investment in joint venture		223.3		223.3		183.7
Other assets, net		82.7		82.7		88.8
	$	5,613.9	$	5,613.9	$	5,667.4
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Due to general partner and affiliates	$	56.4	$	56.4	$	41.3
Accounts payable and other		278.5		278.5		314.5
Accrued purchases		450.3		450.3		494.3
Property and other taxes payable		9.5		9.5		16.4
Distribution payable to EEP		811.3		—		—
		1,606.0		794.7		866.5
Other long-term liabilities		72.5		72.5		86.7
		1,678.5		867.2		953.2
Commitments and contingencies
Partners’ capital
Limited partner interest		3,929.0		4,740.3		4,707.1
General partner interest		—		—		—
Accumulated other comprehensive income		6.4		6.4		7.1
Total partners’ capital		3,935.4		4,746.7		4,714.2
	$	5,613.9	$	5,613.9	$	5,667.4

The accompanying notes are an integral part of these consolidated financial statements.

F-56

MIDCOAST OPERATING, L.P. (f/k/a ENBRIDGE MIDCOAST ENERGY, L.P.)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. ORGANIZATION AND NATURE OF OPERATIONS

General

Midcoast Operating, L.P., formerly known as Enbridge Midcoast Energy, L.P., together with its consolidated subsidiaries, which are referred to herein as “we,” “us,” “our” and “Midcoast Operating,” is a growth-oriented Delaware limited partnership that is wholly owned by Enbridge Energy Partners, L.P., or EEP. We own and operate a portfolio of assets engaged in the business of gathering, processing and treating natural gas, as well as the transportation and marketing of natural gas, natural gas liquids, or NGLs, and condensate. Our portfolio of natural gas and NGL pipelines, plants and related facilities are geographically concentrated in the Gulf Coast and Mid-Continent regions of the United States, primarily in Texas and Oklahoma. We also own and operate natural gas and NGL logistics and marketing assets that primarily support our gathering, processing and transportation business. We hold our assets in a series of limited partnerships and limited liability companies that we wholly own either directly or indirectly.

Our capital accounts consist of general partner interest held by Enbridge Midcoast Holdings, L.L.C., a wholly owned subsidiary of EEP and limited partner interests held directly by EEP. At March 31, 2013 and December 31, 2012, our equity interests were distributed as follows:

Limited partner interests	99.999	%
General partner interests	0.001	%

Enbridge Energy Partners, L.P.

EEP was formed in 1991 by Enbridge Energy Company, Inc., its general partner, an indirect, wholly-owned subsidiary of Enbridge Inc., which we refer to as Enbridge, a leading energy transportation and distribution company located in Calgary, Alberta, Canada. EEP was formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership, which owns the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada.

EEP is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets and, through its ownership interests in us, natural gas gathering, treating, processing, transmission and marketing assets in the United States of America. EEP’s Class A common units are traded on the New York Stock Exchange, or NYSE, under the symbol EEP.

Enbridge Energy Management, L.L.C.

Enbridge Energy Management, L.L.C., which we refer to as Enbridge Management, is a Delaware limited liability company that was formed in May 2002. EEP’s general partner, through Enbridge Management’s direct ownership of the voting shares of Enbridge Management, elects all of its directors. Enbridge Management’s listed shares are traded on the NYSE under the symbol EEQ. Enbridge Management owns all of a special class of EEP’s limited partner interests and derives all of its earnings from its investment in EEP.

Enbridge Management’s principal activity is managing the business and affairs of EEP pursuant to a delegation of control agreement among EEP’s general partner, Enbridge Management and EEP. The delegation of control agreement provides that Enbridge Management will not amend or propose to amend EEP’s partnership agreement, allow a merger or consolidation involving EEP, allow a sale or exchange of all or substantially all of

F-57

our assets or dissolve or liquidate EEP without the approval of EEP’s general partner. In accordance with its limited liability company agreement, Enbridge Management’s activities are restricted to being a limited partner of EEP and managing its business and affairs.

Enbridge Inc.

Enbridge Inc., which we refer to as Enbridge, is the indirect parent of EEP’s general partner, and its common shares are publicly traded on the NYSE in the United States and the Toronto Stock Exchange in Canada under the symbol ENB. Enbridge is a leader in energy transportation and distribution in North America, with a focus on crude oil and liquids pipelines, natural gas pipelines, natural gas distribution and renewable energy. At December 31, 2012 and 2011, Enbridge and its consolidated subsidiaries held an effective 21.8% and 23.0% interest in EEP, respectively, through its ownership in Enbridge Management and EEP’s general partner.

2. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or U.S. GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by U.S. GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of March 31, 2013, our results of operations for the three month periods ended March 31, 2013 and 2012 and our cash flows for the three month periods ended March 31, 2013 and 2012. Our results of operations for the three month period ended March 31, 2013 should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for crude oil, seasonality of portions of our gathering, processing and transportation and logistics and marketing businesses, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value.

Supplemental Pro Forma Information—Staff Accounting Bulletin 1.B.3 requires that certain distribution to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of Midcoast Energy Partners, L.P.’s proposed initial public offering, Midcoast Energy Partners, L.P. intends to distribute approximately $811.3 million to EEP. The supplemental pro forma statement of financial position as of March 31, 2013, gives pro forma effect to the assumed distribution as though it had been declared and was payable as of that date.

3. INVENTORY

Our inventory is comprised of the following:

	March 31,		December 31,
	2013		2012
	(in millions)
Materials and supplies	$	0.4	$	0.4
Crude oil inventory		7.3		10.1
Natural gas and NGL inventory		69.2		64.3
	$	76.9	$	74.8

Cost of natural gas and natural gas liquids on our consolidated statements of income includes charges totaling $0.8 million and $2.4 million for the three month periods ended March 31, 2013 and 2012, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs to reflect the current market value.

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4. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment is comprised of the following:

	Depreciation Rates(1)		March 31, 2013			December 31, 2012
			(in millions)
Land		—	$	8.7		$	8.7
Rights-of-way		2.08%—7.14%		345.8			340.3
Pipelines		0.29%—6.70%		1,630.8			1,603.8
Pumping equipment, buildings and tanks		1.48%—6.67%		67.1			65.4
Compressors, meters and other operating equipment		2.01%—20.00%		1,781.6			1,755.7
Vehicles, office furniture and equipment		2.19%—33.33%		139.4			133.0
Processing and treating plants		2.18%—4.00%		492.6			489.8
Construction in progress				393.9			402.2
Total property, plant and equipment				4,859.9			4,798.9
Accumulated depreciation				(868.8	)		(835.9	)
Property, plant and equipment, net			$	3,991.1		$	3,963.0

⁽¹⁾  We have assets included in the above table that are almost fully depreciated, which yield depreciation rates that suggest these assets have significant remaining useful lives, but in fact have little remaining net book value in relation to their expected service lives.

5. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with commodity price risks through 2016 in accordance with our risk management policies.

Accounting Treatment

We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply the market approach to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimates of fair value.

In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in cost of natural gas and natural gas liquids for our commodity-based derivatives. Cash flow is

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only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in cost of natural gas and natural gas liquids for commodity hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Non-Qualified Hedges

Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in cost of natural gas and natural gas liquids in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.

The following transaction types do not qualify for hedge accounting and contribute to volatility in our earnings and in our cash flows upon settlement:

Commodity Price Exposures:

• Transportation—In our logistics and marketing business, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.

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• Storage—In our logistics and marketing business, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical natural gas or NGLs are recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas and NGL storage activities can increase volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

• Optional Natural Gas Processing Volumes—In our gathering, processing and transportation business, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

• NGL Forward Contracts—In our logistics and marketing business, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. In the second quarter of 2009, we determined that a sub-group of physical NGL sales contracts with terms allowing for economic net settlement did not qualify for the normal purchases and normal sales, or NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.

• Natural Gas Forward Contracts—In our logistics and marketing business, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In the first quarter of 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.

• Natural Gas Options—In our gathering, processing and transportation business, we use options to hedge the forecasted commodity exposure of our NGLs and natural gas. Although options can qualify for hedge accounting treatment, pursuant to the authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These

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derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of NGLs and natural gas until the underlying long-term transactions are settled.

In all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated

We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in cost of natural gas and natural gas liquids line item on our consolidated statements of income.

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net unrealized gains and losses associated with the changes in fair value of our derivative financial instruments:

	Three months ended March,  31
	2013			2012
	(unaudited; in millions)
Gathering, processing, and transportation business
Hedge ineffectiveness	$	0.5		$	(1.8	)
Non-qualified hedges		0.9			3.2
Logistics and Marketing business
Non-qualified hedges		(2.9	)		0.5
Derivative fair value net gains (losses)	$	(1.5	)	$	1.9

Derivative Positions

Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:

	March 31,			December 31,
	2013			2012
	(in millions)
Other current assets	$	254.1		$	275.0
Other assets, net		68.2			78.1
Accounts payable and other		(245.3	)		(259.9	)
Other long-term liabilities		(64.0	)		(78.0	)
	$	13.0		$	15.2

The changes in the net assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of long-term natural gas, NGL and crude oil sales and purchase contracts.

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We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $2.7 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the three month period ended March 31, 2013, no unrealized commodity hedge amounts were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that there will be no financial impact from the reclassifications from AOCI to earnings during the next twelve months for any unrealized net losses or gains from our cash flow hedging activities based on pricing and positions at March 31, 2013.

The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).

	March 31,			December 31,
	2013			2012
	(in millions)
Counterparty Credit Quality*
AA	$	(105.5	)	$	(116.6	)
A		(161.2	)		(150.4	)
Lower than A		279.7			282.2
	$	13.0		$	15.2

* As determined by nationally-recognized statistical ratings organizations.

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA^®, financial contracts, we have the right to require collateral from our counterparties. We would include any cash collateral received in the balances listed above, however, as of March 31, 2013 and December 31, 2012 we are holding no cash collateral on our asset exposures. When we are in a position of posting collateral to cover our counterparties’ exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.

The ISDA^® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA^® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

The ISDA^® agreements, in combination with the master netting agreements, and credit arrangements governing our commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. EEP generally provides letters of credit to satisfy such collateral requirements under our ISDA^® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

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At March 31, 2013 and December 31, 2012, we had credit concentrations in the following industry sectors, as presented below:

	March 31,			December 31,
	2013			2012
	(in millions)
United States financial institutions and investment banking entities	$	(191.0	)	$	(204.7	)
Non-United States financial institutions		(76.0	)		(87.4	)
Integrated oil companies		—			4.5
Other		280.0			302.8
	$	13.0		$	15.2

Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. A reconciliation between the derivative balances presented at gross values rather than the net amounts we present in our other derivative disclosures, is also provided below.

Effect of Derivative Instruments on the Consolidated Statements of Financial Position

	Asset Derivatives					Liability Derivatives
		Fair Value at					Fair Value at
	Financial Position Location	March 31,		December 31,		Financial Position Location	March 31,			December 31,
		2013		2012			2013			2012
	(in millions)
Derivatives designated as hedging instruments(1)
Commodity contracts	Other current assets	$	12.0	$	16.9	Accounts payable and other	$	(10.0	)	$	(9.9	)
Commodity contracts	Other assets, net		6.0		4.5	Other long-term liabilities		(3.2	)		(5.6	)
			18.0		21.4			(13.2	)		(15.5	)
Derivatives not designated as hedging instruments
Interest Rate contracts	Other current assets(2)		233.4		246.9	Accounts payable and other(2)		(233.4	)		(246.9	)
Interest Rate contracts	Other assets, net(2)		65.7		71.6	Other long-term liabilities(2)		(65.7	)		(71.6	)
Commodity contracts	Other current assets(2)		11.3		13.1	Accounts payable and other(2)		(9.4	)		(11.5	)
Commodity contracts	Other assets, net(2)		11.7		12.6	Other long-term liabilities(2)		(10.8	)		(12.2	)
Other contracts	Other current assets		13.8		14.9	Accounts payable and other		(8.8	)		(8.4	)
Other contracts	Other assets, net		0.7		0.8	Other long-term liabilities		(0.3	)		—
			336.6		359.9			(328.4	)		(350.6	)
Total derivative instruments		$	354.6	$	381.3		$	(341.6	)	$	(366.1	)

⁽¹⁾  Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.

⁽²⁾  Includes both affiliate and third party transactions.

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Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)			Location of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective  Portion)			Location of Gain (loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)	Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)
	(in millions)
For the three month ended March 31, 2013
Commodity contracts	$	(1.6	)	Cost of natural gas and natural gas liquids	$	1.5		Cost of natural gas and natural gas liquids	$	0.5
Total	$	(1.6	)		$	1.5			$	0.5
For the three month ended March 31, 2012
Commodity contracts	$	(3.9	)	Cost of natural gas and natural gas liquids	$	(6.6	)	Cost of natural gas and natural gas liquids	$	(1.9	)
Total	$	(3.9	)		$	(6.6	)		$	(1.9	)

⁽¹⁾  Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

Components of Accumulated Other Comprehensive Income/(Loss)

	Cash Flow Hedges
	(in millions)
Balance at December 31, 2012	$	7.1
Other Comprehensive Income before reclassifications		0.8
Amounts reclassified from AOCI(1)		(1.5	)
Net Other Comprehensive Income		(0.7	)
Balance at March 31, 2013	$	6.4

⁽¹⁾  For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

Reclassifications from Accumulated Other Comprehensive Income

	March 31,
	2013			2012
	(in millions)
Losses (gains) on cash flow hedges:
Commodity Contracts(1)	$	(1.5	)	$	6.6
Total Reclassifications from AOCI	$	(1.5	)	$	6.6

⁽¹⁾  Loss (gain) reported within cost of natural gas and natural gas liquids in the Consolidated Statements of Income.

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Effect of Derivative Instruments on Consolidated Statements of Income

		Three months ended March 31,
		2013			2012
	Location of Gain or (Loss) Recognized in Earnings	Amount of Gain or (Loss)
Derivatives Not Designated as Hedging Instruments		Recognized in Earnings(1)
		(in millions)
Commodity contracts	Cost of natural gas and natural gas liquids	$	(2.0	)	$	3.7
Total Reclassifications from AOCI		$	(2.0	)	$	3.7

⁽¹⁾  Includes only net gains or losses associated with those derivatives that do not qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	March 31, 2013								December 31, 2012
	Assets			Liabilities			Total		Assets			Liabilities			Total
	(in millions)
Fair value of derivatives—gross presentation	$	354.6		$	(341.6	)	$	13.0	$	381.3		$	(366.1	)	$	15.2
Effects of netting agreements		(32.3	)		32.3			—		(28.2	)		28.2			—
Fair value of derivatives—net presentation	$	322.3		$	(309.3	)	$	13.0	$	353.1		$	(337.9	)	$	15.2

We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a net basis by counterparty. The terms of the ISDA^®, which governs our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party.

Offsetting of Financial Assets and Derivative Assets

	March 31, 2013
	Gross Amount of Recognized Assets		Gross Amount Offset in the Statement of Financial Position			Net Amount of Assets Presented in the Statement of Financial Position		Gross Amount Not Offset in the Statement of Financial Position			Net Amount
	(in millions)
Description:
Derivatives	$	354.6	$	(32.3	)	$	322.3	$	(1.1	)	$	321.2
Total	$	354.6	$	(32.3	)	$	322.3	$	(1.1	)	$	321.2

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Offsetting of Financial Liabilities and Derivative Liabilities

	March 31, 2013
	Gross Amount of Recognized Liabilities			Gross Amount Offset in the Statement of Financial Position		Net Amount of Liabilities Presented in the Statement of Financial Position			Gross Amount Not Offset in the Statement of Financial Position		Net Amount
	(in millions)
Description:
Derivatives	$	(341.6	)	$	32.3	$	(309.3	)	$	1.1	$	(308.2	)
Total	$	(341.6	)	$	32.3	$	(309.3	)	$	1.1	$	(308.2	)

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2013 and December 31, 2012. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.

	March 31, 2013									December 31, 2012
	Level 1		Level 2			Level 3		Total		Level 1		Level 2			Level 3		Total
	(in millions)
Commodity contracts:
Financial	$	—	$	(9.0	)	$	11.3	$	2.3	$	—	$	(7.0	)	$	8.4	$	1.4
Physical		—		—			5.5		5.5		—		—			7.4		7.4
Commodity options		—		—			5.2		5.2		—		—			6.4		6.4
Total	$	—	$	(9.0	)	$	22.0	$	13.0	$	—	$	(7.0	)	$	22.2	$	15.2

Qualitative Information about Level 3 Fair Value Measurements

Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimates of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (natural gas, NGLs, and crude oil) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would decrease the fair value of the positions.

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Quantitative Information About Level 3 Fair Value Measurements

Contract Type	Fair Value March 31, 2013(2)				Range(1)
			Valuation Technique	Unobservable Input	Lowest			Highest			Weighted Average			Units
	(in millions)
Commodity Contracts—Financial
Natural Gas	$	4.6	Market Approach	Forward Gas Price	$	3.81		$	4.45		$	4.12		MMBtu
Crude Oil	$	—	Market Approach	Forward Crude Price	$	—		$	—		$	—		Bbl
NGLs	$	6.7	Market Approach	Forward NGL Price	$	0.30		$	2.15		$	1.32		Gal
Commodity Contracts—Physical
Natural Gas	$	0.6	Market Approach	Forward Gas Price	$	3.80		$	4.61		$	4.14		MMBtu
Crude Oil	$	1.8	Market Approach	Forward Crude Price	$	87.80		$	121.04		$	88.40		Bbl
NGLs	$	3.1	Market Approach	Forward NGL Price	$	0.02		$	2.37		$	0.71		Gal
Commodity Options
Natural Gas, Crude and NGLs	$	5.2	Option Model	Option Volatility		33	%		108	%		41	%
Total Fair Value	$	22.0

⁽¹⁾  Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for Crude Oil.

⁽²⁾  Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.3 million of losses.

Contract Type	Fair Value  December  31, 2012(2)					Range(1)
				Valuation Technique	Unobservable Input	Lowest			Highest			Weighted Average			Units
	(in millions)
Commodity Contracts—Financial
Natural Gas	$	8.8		Market Approach	Forward Gas Price	$	3.21		$	4.31		$	3.54		MMBtu
Crude Oil	$	—		Market Approach	Forward Crude Price	$	—		$	—		$	—		Bbl
NGLs	$	(0.4	)	Market Approach	Forward NGL Price	$	0.25		$	2.21		$	1.40		Gal
Commodity Contracts—Physical
Natural Gas	$	1.7		Market Approach	Forward Gas Price	$	3.19		$	4.58		$	3.73		MMBtu
Crude Oil	$	2.6		Market Approach	Forward Crude Price	$	65.22		$	116.56		$	94.31		Bbl
NGLs	$	3.1		Market Approach	Forward NGL Price	$	—		$	2.22		$	0.61		Gal
Commodity Options
Natural Gas, Crude and NGLs	$	6.4		Option Model	Option Volatility		29	%		104	%		40	%
Total Fair Value	$	22.2

⁽¹⁾  Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas, dollars per Gallon, or Gal, for NGLs and dollars per barrel, or Bbl, for Crude Oil.

⁽²⁾  Fair values are presented in millions and include credit valuation adjustments of approximately $0.1 million of losses.

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The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from December 31, 2012 to March 31, 2013. No transfers of assets between any of the Levels occurred during the period.

	Commodity Financial Contracts			Commodity Physical Contracts			Commodity Options			Total
	(in millions)
Beginning balance as of January 31, 2013	$	8.4		$	7.4		$	6.4		$	22.2
Transfers in (out) of Level 3(1)		—			—			—			—
Gains or losses
Included in earnings (or changes in net assets)		2.0			8.8			(1.0	)		9.8
Included in other comprehensive income		4.2			—			—			4.2
Purchases, issuances, sales and settlements
Purchases		—			—			0.6			0.6
Settlements(2)		(3.3	)		(10.7	)		(0.8	)		(14.8	)
Ending balance as of March 31, 2013	$	11.3		$	5.5		$	5.2		$	22.0
Amount of changes in net assets attributable to the change in unrealized gains or losses related to assets still held at the reporting date	$	5.5		$	4.4		$	(0.4	)	$	9.5
Amounts reported in operating revenue	$	—		$	—		$	—		$	—

⁽¹⁾  Our policy is to recognize transfers as of the last day of the reporting period.

⁽²⁾  Settlements represent the realized portion of forward contracts.

F-69

Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at March 31, 2013 and December 31, 2012.

	March 31, 2013													December 31, 2012
				Wtd. Average Price(2)					Fair Value(3)					Fair Value(3)
	Commodity	Notional		Receive		Pay			Asset		Liability			Asset		Liability
Portion of contracts maturing in 2013
Swaps
Receive variable/pay fixed	Natural Gas		1,932,100	$	3.99	$	(3.54	)	$	0.9	$	(0.1	)	$	0.2	$	(0.3	)
	NGL		603,000	$	53.94	$	(50.61	)	$	2.0	$	—		$	1.4	$	—
	Crude Oil		396,550	$	96.78	$	(100.64	)	$	—	$	(1.5	)	$	0.2	$	(3.9	)
Receive fixed/pay variable	Natural Gas		3,634,500	$	4.92	$	(4.05	)	$	3.5	$	(0.4	)	$	7.8	$	—
	NGL		2,318,125	$	53.01	$	(52.03	)	$	8.0	$	(5.7	)	$	9.3	$	(9.9	)
	Crude Oil		1,320,225	$	92.00	$	(96.79	)	$	3.1	$	(9.4	)	$	6.3	$	(8.9	)
Receive variable/pay variable	Natural Gas		40,361,000	$	4.05	$	(4.03	)	$	1.0	$	(0.2	)	$	1.2	$	(0.2	)
Physical Contracts
Receive variable/pay fixed	NGL		830,000	$	40.87	$	(36.72	)	$	3.9	$	(0.5	)	$	0.6	$	(0.8	)
	Crude Oil		126,000	$	97.33	$	(96.14	)	$	0.3	$	(0.1	)	$	0.4	$	(0.4	)
Receive fixed/pay variable	NGL		1,593,115	$	39.04	$	(40.87	)	$	0.5	$	(3.4	)	$	2.6	$	(2.2	)
	Crude Oil		195,000	$	95.72	$	(97.42	)	$	0.1	$	(0.5	)	$	0.3	$	(1.0	)
Receive variable/pay variable	Natural Gas		38,822,722	$	4.06	$	(4.05	)	$	0.6	$	(0.5	)	$	0.9	$	—
	NGL		7,164,820	$	40.23	$	(39.85	)	$	5.4	$	(2.7	)	$	5.2	$	(2.3	)
	Crude Oil		1,167,990	$	100.18	$	(98.52	)	$	4.4	$	(2.4	)	$	6.4	$	(3.0	)
Portion of contracts maturing in 2014
Swaps
Receive variable/pay fixed	Natural Gas		21,870	$	4.31	$	(5.22	)	$	—	$	—		$	—	$	—
	NGL		60,000	$	82.95	$	(85.26	)	$	—	$	(0.1	)	$	—	$	—
	Crude Oil		506,255	$	92.75	$	(101.95	)	$	—	$	(4.6	)	$	—	$	(4.9	)
Receive fixed/pay variable	Natural Gas		2,496,900	$	4.01	$	(4.20	)	$	—	$	(0.5	)	$	0.2	$	—
	NGL		892,425	$	63.63	$	(62.10	)	$	3.0	$	(1.6	)	$	0.9	$	(2.7	)
	Crude Oil		1,361,955	$	94.22	$	(92.79	)	$	5.1	$	(3.1	)	$	5.4	$	(2.8	)
Receive variable/pay variable	Natural Gas		8,112,500	$	4.31	$	(4.30	)	$	0.2	$	(0.1	)	$	0.1	$	(0.1	)
Physical Contracts
Receive variable/pay variable	Natural Gas		21,409,275	$	4.33	$	(4.32	)	$	0.5	$	(0.4	)	$	0.5	$	—
	NGL		4,182,500	$	18.23	$	(18.27	)	$	—	$	(0.2	)	$	—	$	—
Portion of contracts maturing in 2015
Swaps
Receive variable/pay fixed	Crude Oil		515,015	$	89.33	$	(100.93	)	$	—	$	(5.9	)	$	—	$	(5.6	)
Receive fixed/pay variable	NGL		109,500	$	88.36	$	(77.40	)	$	1.2	$	—		$	0.7	$	(0.2	)
	Crude Oil		865,415	$	97.72	$	(89.33	)	$	7.3	$	(0.1	)	$	6.8	$	(0.2	)
Physical Contracts
Receive variable/pay variable	Natural Gas		8,468,425	$	4.34	$	(4.30	)	$	0.4	$	(0.1	)	$	0.4	$	—
Portion of contracts maturing in 2016
Swaps
Receive fixed/pay variable	Crude Oil		45,750	$	99.31	$	(86.97	)	$	0.6	$	—		$	0.5	$	—
Physical Contracts
Receive variable/pay variable	Natural Gas		783,240	$	4.50	$	(4.38	)	$	0.1	$	—		$	0.1	$	—

(1) Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbls.

(2) Weighted average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGL and crude oil.

(3) The fair value is determined based on quoted market prices at March 31, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.2 million of losses and $0.2 million of losses at March 31, 2013 and December 31, 2012, respectively.

F-70

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at March 31, 2013 and December 31, 2012.

	March 31, 2013													December 31, 2012
	Commodity	Notional(1)		Strike Price(2)		Market Price(2)			Fair Value(3)					Fair Value(3)
									Asset		Liability			Asset		Liability
Portion of option contracts maturing in 2013
Puts (purchased)	Natural Gas		1,237,500	$	4.18	$	(3.99	)	$	0.5	$	—		$	1.4	$	—
	NGL		367,000	$	31.90	$	(28.34	)	$	2.7	$	—		$	3.7	$	—
Portion of option contracts maturing in 2014
Puts (purchased)	NGL		264,250	$	52.46	$	(50.87	)	$	2.4	$	—		$	1.3	$	—
Calls (written)	NGL		136,500	$	54.17	$	(40.34	)	$	—	$	(0.4	)	$	—	$	—

⁽¹⁾  Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbls.

⁽²⁾  Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.

⁽³⁾  The fair value is determined based on quoted market prices at March 31, 2013 and December 31, 2012, respectively, discounted using the swap rate for the respective periods to consider the time value of money.

Fair Value Measurements of Interest Rate Derivatives

We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.

							Fair Value
Date of Maturity & Contract Type(1)	Accounting Treatment	Notional		Average Fixed  Rate(2)			March 31, 2013			December 31, 2012
		(dollars in millions)
Contracts maturing in 2013
Interest Rate Swaps-Pay Fixed	Non-qualifying	$	600		4.15	%	$	(16.7	)	$	(22.6	)
Interest Rate Swaps-Pay Float	Non-qualifying	$	600		4.15	%	$	16.7		$	22.6
Contracts maturing in 2014
Interest Rate Swaps-Pay Fixed	Non-qualifying	$	200		0.56	%	$	(0.5	)	$	(0.6	)
Interest Rate Swaps-Pay Float	Non-qualifying	$	200		0.56	%	$	0.5		$	0.6
Contracts maturing in 2015
Interest Rate Swaps-Pay Fixed	Non-qualifying	$	300		2.43	%	$	(6.7	)	$	(6.7	)
Interest Rate Swaps-Pay Float	Non-qualifying	$	300		2.43	%	$	6.7		$	6.7
Contracts maturing in 2017
Interest Rate Swaps-Pay Fixed	Non-qualifying	$	400		2.21	%	$	(16.0	)	$	(16.0	)
Interest Rate Swaps-Pay Float	Non-qualifying	$	400		2.21	%	$	16.0		$	16.0
Contracts maturing in 2018
Interest Rate Swaps-Pay Fixed	Non-qualifying	$	500		2.08	%	$	(1.7	)	$	(1.8	)
Interest Rate Swaps-Pay Float	Non-qualifying	$	500		2.08	%	$	1.7		$	1.8
Contracts settling prior to maturity
2013-Pre-issuance Hedges	Non-qualifying	$	2,200		4.51	%	$	—		$	—
2014-Pre-issuance Hedges	Non-qualifying	$	1,500		3.15	%	$	—		$	—
2016-Pre-issuance Hedges	Non-qualifying	$	500		2.85	%	$	—		$	—

(1) Includes both affiliate and third party transactions.

(2) Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.

F-71

6. INCOME TAXES

We are not a taxable entity for United States federal income tax purposes, or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws that apply to entities organized as partnerships by the State of Texas.

We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. The Texas state income tax rate was 0.4% and 0.5% for the three month periods ended March 31, 2013 and 2012, respectively. Our income tax expense is $0.5 million and $0.6 million for the three month periods ended March 31, 2013 and 2012, respectively. At March 31, 2013 and December 31, 2012, we have included a current income tax payable of $4.1 million and $3.7 million in “Property and other taxes payable,” respectively. In addition, at March 31, 2013 and December 31, 2012, we have included a deferred income tax liability of $3.1 million and $3.0 million, respectively, in “Other long-term liabilities,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

7. SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.

Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We conduct our business through two distinct reporting segments: gathering, processing and transportation and logistics and marketing.

F-72

The following tables present certain financial information relating to our business segments and corporate activities:

	As of and for the three month period ended March 31, 2013
	Gathering, processing and transportation		Logistics and marketing
						Corporate(1)			Total
	(unaudited; in millions)
Total revenue	$	659.2	$	1,223.0		$	—		$	1,882.2
Less: Intersegment revenue		487.0		24.9			—			511.9
Operating revenue		172.2		1,198.1			—			1,370.3
Cost of natural gas and natural gas liquids		17.4		1,178.7			—			1,196.1
Segment gross margin		154.8		19.4			—			174.2
Operating and maintenance		64.2		19.2			—			83.4
General and administrative		21.9		2.6			—			24.5
Depreciation and amortization		33.5		1.7			—			35.2
		119.6		23.5			—			143.1
Operating income (loss)		35.2		(4.1	)		—			31.1
Other income (expense)		—		—			0.1			0.1
Income (loss) before income tax expense		35.2		(4.1	)		0.1			31.2
Income tax expense		—		—			0.5			0.5
Net income (loss)	$	35.2	$	(4.1	)	$	(0.4	)	$	30.7
Total assets(2)	$	4,533.1	$	843.2		$	237.6		$	5,613.9
Capital expenditures (excluding acquisitions)	$	66.3	$	4.6		$	—		$	70.9

⁽¹⁾  Corporate consists of income taxes, which are not allocated to the business segments.

⁽²⁾  Total assets for our gathering, processing and transportation business includes our long-term equity investment in the Texas Express NGL system.

	As of and for the three month period ended March 31, 2012
	Gathering, processing and transportation		Logistics and marketing
						Corporate(1)			Total
	(unaudited; in millions)
Total revenue	$	695.7	$	1,328.8		$	—		$	2,024.5
Less: Intersegment revenue		505.8		22.8			—			528.6
Operating revenue		189.9		1,306.0			—			1,495.9
Cost of natural gas and natural gas liquids		11.0		1,295.2			—			1,306.2
Segment gross margin		178.9		10.8			—			189.7
Operating and maintenance		65.5		20.8			—			86.3
General and administrative		22.1		10.3			—			32.4
Depreciation and amortization		31.3		1.8			—			33.1
		118.9		32.9			—			151.8
Operating income (loss)		60.0		(22.1	)		—			37.9
Other income (expense)		—		—			(0.1	)		(0.1	)
Income (loss) before income tax expense		60.0		(22.1	)		(0.1	)		37.8
Income tax expense		—		—			0.6			0.6
Net income (loss)	$	60.0	$	(22.1	)	$	(0.7	)	$	37.2
Total assets(2)	$	4,118.5	$	716.1		$	237.2		$	5,071.8
Capital expenditures (excluding acquisitions)	$	100.0	$	16.7		$	—		$	116.7

⁽¹⁾  Corporate consists of income taxes, which are not allocated to the business segments.

⁽²⁾  Total assets for our gathering, processing and transportation business includes our long-term equity investment in the Texas Express NGL system.

F-73

8. SUBSEQUENT EVENTS

Distribution to Partners

On April 30, 2013, the board of directors of Enbridge Management declared a distribution payable to our partners on May 15, 2013. We distributed cash to our partners of $ 58.9 million on May 15, 2013.

F-74

Appendix A

Form of First Amended and Restated

Agreement of Limited Partnership of Midcoast Energy Partners, L.P.

To be filed by amendment.

A-1

Appendix B

Glossary of Terms

Bbl: Barrel of liquids (approximately 42 United States gallons).

Bcf: One billion cubic feet.

Bcf/d: One billion cubic feet per day.

Bpd: Barrels per day.

common carrier pipeline: A pipeline engaged in the transportation of crude oil, refined petroleum products or NGL as a common carrier for hire.

condensate: A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.

crude oil: A mixture of hydrocarbons that exists in liquid phase in underground reservoirs.

dry gas: A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.

end user: The ultimate user and consumer of transported energy products.

FERC: Federal Energy Regulatory Commission.

formation: A geological term for a unit of rock strata that is sufficiently distinctive for mapping purposes.

fractionation: Fractionation is accomplished by controlling the temperature and pressure of the stream of mixed NGL in order to take advantage of the different boiling points of separate components. NGL fractionation facilities separate mixed NGL streams into discrete components such as ethane, propane, normal butane, isobutane and natural gasoline.

liquefied natural gas or LNG: Natural gas that has been cooled to -259 degrees Fahrenheit (-161 degrees Celsius) and at which point it is condensed into a liquid which is colorless, odorless, non-corrosive and non-toxic. Characterized as a cryogenic liquid.

MBbls: One thousand barrels.

MBbls/d: One thousand barrels per day.

Mcf: One thousand cubic feet. One Mcf equals the heating value of one MMBtu.

Mcf/d: One thousand cubic feet per day.

medium crude oil: A type of crude oil with an API gravity between light and heavy crude oil.

MMBbls: One million barrels.

MMBtu: One million British thermal units.

B-1

MMBtu/d: One million British thermal units per day.

MMcf: One million cubic feet.

MMcf/d: One million cubic feet per day.

NGL or NGLs: Natural gas liquids. The combination of ethane, propane, normal butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: The New York Mercantile Exchange.

OPIS: The Oil Price Information Service.

PHMSA: Pipeline and Hazardous Materials Safety Administration.

play: A proven geological formation that contains commercial amounts of hydrocarbons.

POL: Percentage-of-liquids processing contract.

POP: Percentage-of-proceeds processing contract.

PPI: Producer Price Index for Finished Goods, as provided by the U.S. Department of Labor, Bureau of Labor Statistics.

receipt point: The point where production is received by or into a gathering system or transportation pipeline.

rich gas: Natural gas which contains significant amounts of heavier hydrocarbons which act to increase the calorific (or heating) value of the gas.

SCADA: Supervisory Control and Data Acquisition.

Tcf: One trillion cubic feet.

throughput: The volume of crude oil and refined petroleum products transported or passing through a pipeline, plant, terminal or other facility during a particular period.

U. S. GAAP: United States generally accepted accounting principles.

wellhead: The equipment at the surface of a well that is used to control the well’s pressure; also, the point at which the hydrocarbons and water exit the ground.

B-2

Through and including                     , 2013 (the 25th day after the date of this prospectus), federal securities laws may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

Common units

Representing limited partner interests

Midcoast Energy Partners, L.P.

PROSPECTUS

BofA Merrill Lynch

                    , 2013

Part II

Information Not Required in the Registration Statement

Item 13. Other expenses of issuance and distribution

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the NYSE filing fee, the amounts set forth below are estimates.

SEC registration fee	$	78,430
FINRA filing fee		86,750
NYSE listing fee		*
Advisory fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*

* To be filed by amendment.

Item 14. Indemnification of directors and officers

The section of the prospectus entitled “Our Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section              of the Underwriting Agreement to be filed as an exhibit to this registration statement in which Midcoast Energy Partners, L.P. and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15. Recent sales of unregistered securities

On May 30, 2013, in connection with the formation of the partnership, Midcoast Energy Partners, L.P. issued to (i) Midcoast Holdings, L.L.C. the 2% general partner interest in the partnership for $20 and (ii) EEP the 98% limited partner interest in the partnership for $980 in an offering exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

II-1

Item 16. Exhibits

The following documents are filed as exhibits to this registration statement:

Exhibit number	Description
1.1*	Form of Underwriting Agreement (including form of Lock-up Agreement)
3.1	Certificate of Limited Partnership of Midcoast Energy Partners, L.P.
3.2*	Form of First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P. (included as Appendix A to the Prospectus)
5.1*	Opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1*	Opinion of Latham & Watkins LLP relating to tax matters
10.1*	Form of Credit Agreement
10.2*	Form of Contribution, Conveyance and Assumption Agreement
10.3*	Form of Long-Term Incentive Plan
10.4*	Form of Intercorporate Services Agreement
10.5*	Form of Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P.
10.6*	Form of Financial Support Agreement
10.7*	Allocation Agreement
21.1*	List of Subsidiaries of Midcoast Energy Partners, L.P.
23.1	Consent of PricewaterhouseCoopers LLP
23.2*	Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
23.3*	Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
24.1	Powers of Attorney (contained on the signature page to this Registration Statement)

* To be filed by amendment.

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-2

The undersigned registrant hereby undertakes that,

(i) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(ii) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with EEP or its subsidiaries (including the registrant’s general partner) and of fees, commissions, compensation and other benefits paid, or accrued to EEP or its subsidiaries (including the registrant’s general partner) for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

II-3

Signatures

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on June 14, 2013.

Midcoast Energy Partners, L.P.
BY:	Midcoast Holdings, L.L.C. its General Partner
BY:	/s/ Mark A. Maki
	Mark A. Maki
	President

Each person whose signature appears below appoints Mark A. Maki, Terrance L. McGill, Stephen J. Neyland and Chris Kaitson, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities indicated on June 14, 2013.

Signature	Title
/s/ Mark A. Maki Mark A. Maki	President and Director (Principal Executive Officer)
/s/ Terrance L. McGill Terrance L. McGill	Chief Operating Officer and Director
/s/ Stephen J. Neyland Stephen J. Neyland	Vice President—Finance (Principal Financial Officer)
/s/ William M. Ramos William M. Ramos	Controller (Principal Accounting Officer)

II-4

Exhibit Index

Exhibit number	Description
1.1*	Form of Underwriting Agreement (including form of Lock-up Agreement)
3.1	Certificate of Limited Partnership of Midcoast Energy Partners, L.P.
3.2*	Form of First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P. (included as Appendix A to the Prospectus)
5.1*	Opinion of Latham & Watkins LLP as to the legality of the securities being registered
8.1*	Opinion of Latham & Watkins LLP relating to tax matters
10.1*	Form of Credit Agreement
10.2*	Form of Contribution, Conveyance and Assumption Agreement
10.3*	Form of Long-Term Incentive Plan
10.4*	Form of Intercorporate Services Agreement
10.5*	Form of Amended and Restated Agreement of Limited Partnership of Midcoast Operating, L.P.
10.6*	Form of Financial Support Agreement
10.7*	Allocation Agreement
21.1*	List of Subsidiaries of Midcoast Energy Partners, L.P.
23.1	Consent of PricewaterhouseCoopers LLP
23.2*	Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
23.3*	Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
24.1	Powers of Attorney (contained on the signature page to this Registration Statement)

* To be filed by amendment.

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