UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-K

 

x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016
or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from         to        

Commission file number 1-10934

 

ENBRIDGE ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware		39-1715850
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1100 Louisiana Street, Suite 3300, Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code (713) 821-2000

 

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Class A common units		New York Stock Exchange

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 x		Accelerated Filer o
Non-Accelerated Filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x

The aggregate market value of the registrant’s Class A common units held by non-affiliates computed by reference to the price at which the common equity was last sold on June 30, 2016, was $5,002,552,571.

As of February 14, 2017 the registrant has 262,208,428 Class A common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			26
Item 2. Properties			48
Item 3. Legal Proceedings			48
Item 4. Mine Safety Disclosures			48
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of   Equity Securities			49
Item 6. Selected Financial Data			50
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			53
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			90
Item 8. Financial Statements and Supplementary Data			95
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			172
Item 9A. Controls and Procedures			172
Item 9B. Other Information			173
PART III
Item 10. Directors, Executive Officers and Corporate Governance			174
Item 11. Executive Compensation			181
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder   Matters			205
Item 13. Certain Relationships and Related Transactions, and Director Independence			206
Item 14. Principal Accountant Fees and Services			209
PART IV
Item 15. Exhibits and Financial Statement Schedules			210
Signatures			211

In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We refer to our general partner, Enbridge Energy Company, Inc., as our “General Partner.” References to “Enbridge” refer collectively to Enbridge Inc., and its subsidiaries other than us. References to “Enbridge Management” refer to Enbridge Energy Management, L.L.C., the delegate of our General Partner that manages our business and affairs.

This Annual Report on Form 10-K includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “consider,” “continue,” “could,” “estimate,” “evaluate,” “expect,” “explore,” “forecast,” “intend,” “may,” “opportunity,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Annual Report on Form 10-K speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for the supply of, forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and NGLs, including the rate of development of the Alberta Oil Sands; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (5) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B and any additional fines and penalties and injunctive relief assessed in connection with the crude oil release on that line; (6) costs in connection with complying with the settlement consent decree related to Line 6B and Line 6A, which is still subject to court approval, or the failure to receive court approval of, or material modifications to, such decree; (7) changes in or challenges to our tariff rates; (8) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (9) permitting at federal, state and local level or renewals of rights of way. Forward-looking statements regarding sponsor support transactions or sales of assets (to Enbridge or otherwise) are further qualified by the fact that Enbridge is under no obligation to provide additional sponsor support and neither Enbridge nor any third party is under any obligation to offer to buy or sell us assets, and we are under no obligation to buy or

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sell any such assets. As a result, we do not know when or if any such transactions will occur. Any statements regarding sponsor expectations or intentions are based on information communicated to us by Enbridge, but there can be no assurance that these expectations or intentions will not change in the future.

For additional factors that may affect results, see “Item-1A. Risk Factors” included elsewhere in this Annual Report on Form 10-K, which is available to the public over the Internet at the United States Securities and Exchange Commission’s, or the SEC’s, website (www.sec.gov) and at our website (www.enbridgepartners.com).

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Glossary

The following abbreviations, acronyms and terms used in this Form 10-K are defined below:

ACFFO			Available cash flow from operations per share
AEDC			Allowance for equity used during construction
AER			Alberta Energy Regulator
AFUDC			Allowance for funds used in construction
Alberta Clipper Pipeline			A 36-inch pipeline that runs from the Canadian international border near Neche, North Dakota to Superior, Wisconsin on our Lakehead system
Anadarko system			Natural gas gathering and processing assets located in western Oklahoma and the Texas Panhandle which serve the Anadarko basin; inclusive of the Elk City System
AOCI			Accumulated other comprehensive income
ASU			Accounting Standards Update
Bakken Holdings			Bakken Holdings Company LLC
Bbl			Barrel of liquids (approximately 42 United States gallons)
Bpd			Barrels per day
BPI			Bakken Pipeline Investments LLC
Btu			British thermal units
CAA			Clean Air Act of 1970, as amended
CAD			Amount denominated in Canadian dollars
CAO			Corrective Action Order
CAPP			Canadian Association of Petroleum Producers, a trade association representing a majority of our Lakehead system’s customers
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFR			Code of Federal Regulations
CFTC			Commodity Futures Trading Commission
CIAC			Contributions in aid of construction
COSO			Committee of Sponsoring Organizations of the Treadway Commission
CO2e			Carbon Dioxide Equivalent
Credit Facilities			364-Day Credit Facility and the Credit Facility
CWA			Clean Water Act
DAPL			Dakota Access Pipeline
DBRS			Dominion Bond Rating System
DCF			Discounted Cash Flow
DOE			United States Department of Energy
DOT			United States Department of Transportation
EA interests			Partnership interests of the OLP related to all the assets, liabilities and operations of the Eastern Access Projects
East Texas system			Natural gas gathering, treating and processing assets in East Texas that serve the Bossier trend and Haynesville shale areas
Eastern Access Joint Funding Agreement			The funding agreement between Enbridge Energy Partners, L.P. (the Partnership) and Enbridge Energy Company, Inc. (the General Partner) to provide joint funding for the Eastern Access Projects, reflected by the terms of the Series EA partnership interests and the related contribution agreement
Eastern Access Projects			Multiple expansion projects that will provide increased access to refineries in the United States Upper Midwest and in Canada in the provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States
EAW			Environmental Assessment Worksheet
EBITDA			Earnings Before Interest, Taxes, Depreciation and Amortization
EECI			Enbridge Energy Company, Inc.
EES			Enbridge Employee Services Inc., a subsidiary of our General Partner

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EIA			Energy Information Administration
Elk City system			Elk City natural gas gathering and processing system located in western Oklahoma in the Anadarko basin
Enbridge			Enbridge Inc., of Calgary, Alberta, Canada, the ultimate parent of the General Partner
Enbridge Management			Enbridge Energy Management, L.L.C.
Enbridge system			Canadian portion of the liquid petroleum mainline system
Enbridge Pipelines			Enbridge Pipelines Inc.
Enterprise Products			Enterprise Products Partners, L.P.
EOSI			Enbridge Operational Services, Inc.
EP Act			Energy Policy Act of 1992
EPA			Environmental Protection Agency
ETCOP			Energy Transfer Crude Oil Pipeline
EUS			Enbridge (U.S.) Inc.
Exchange Act			Securities Exchange Act of 1934, as amended
FERC			Federal Energy Regulatory Commission
FSM			Facilities Surcharge Mechanism
GDP			Gross Domestic Product
General Partner			Enbridge Energy Company, Inc., the general partner of the Partnership
GHGRP			Greenhouse Gas Reporting Program
IEPC			Illinois Extension Pipeline Company, L.L.C.
IBES			Institutional Brokers’ Estimate System
ICA			Interstate Commerce Act
ICR			Oil and Gas Information
IDRs			Incentive distribution rights
IDUs			Incentive Distribution Units
IJT			International Joint Tariff
IRS			Internal Revenue Service
ISDA®			International Swaps and Derivatives Association, Inc.
ISOP			Incentive Stock Option Plan (2007	)
i-units			Special class of our limited partner interests
Lakehead system			United States portion of the liquid petroleum Mainline system
LIBOR			London Interbank Offered Rate — British Bankers’ Association’s average settlement rate for deposits in United States dollars
Light Oil Market Access Program			Several projects that will provide increased pipeline capacity on our North Dakota regional system, further expand capacity on our U.S. mainline system, upsize the Eastern Access Project, enhance Enbridge’s Canadian mainline terminal capacity and provide additional access to U.S. Midwestern refineries
LTIP			Long-term Incentive Plan
M3			Cubic meters of liquid = 6.2898105 Bbl
Mainline Expansion Joint Funding Agreement			The funding agreement between Enbridge Energy Partners, L.P. (the Partnership) and Enbridge Energy Company, Inc. (the General Partner) to provide joint funding for the U.S. Mainline Expansion projects, reflected by the terms of the Series ME partnership interests and the related contribution agreement
Mainline system			The combined liquid petroleum pipeline operations of our Lakehead system and the Enbridge system, which is 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
MarEn			MarEn Bakken Company LLC
Mcf			Thousand cubic feet
MDEQ			Michigan Department of Environmental Quality
MEP			Midcoast Energy Partners, L.P.

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MEP General Partner			Midcoast Holdings, L.L.C.
Merger			The proposed merger of MergerCo with and into MEP pursuant to the terms and conditions of the Merger Agreement whereby (i) EECI will acquire all of MEP’s outstanding common units not already owned by EECI, EEP or their affiliates, (ii) MergerCo will merge with and into MEP, (iii) the separate limited liability company existence of MergerCo will cease, (iv) and MEP will continue its existence as a limited partnership under Delaware law as the surviving entity in the Merger
Merger Agreement			Agreement and Plan of Merger dated January 26, 2017, with EECI, MergerCo, MEP and Midcoast Holdings, L.L.C., the general partner of MEP
MergerCo			Enbridge Holdings (Leather) L.L.C., an indirect wholly-owned subsidiary of EECI
MIC			Enbridge Management Information Circular
Midcoast Operating			Midcoast Operating, L.P., the operating subsidiary of MEP
Mid-Continent system			Crude oil pipelines and storage facilities located in the Mid-Continent region of the United States and includes the Cushing tank farm and Ozark pipeline
MLP			Master Limited Partnership
MMBtu/d			Million British Thermal units per day
MMBbls			Million Barrels of liquids
MMcf/d			Million cubic feet per day
MNPUC			Minnesota Public Utilities Commission
Moody’s			Moody’s Investors Service
MPC			Marathon Petroleum Corporation
NCI			Noncontrolling interest
NEB			National Energy Board, a Canadian federal agency that regulates Canada’s energy industry
NEOs			Named Executive Officers
NGA			Natural Gas Act of 1938
NGLs			Natural gas liquids
NGPA			Natural Gas Policy Act of 1978
NDPC			North Dakota Pipeline Company, L.L.C.
North Dakota system			Liquids petroleum pipeline gathering system and common carrier pipeline in the Upper Midwest United States that serves the Bakken formation within the Williston basin
North Texas system			Natural gas gathering and processing assets located in the Fort Worth basin serving the Barnett Shale area
NPNS			Normal purchases and normal sales
NSPS			New Source Performance Standards
NTSB			National Transportation Safety Board
NYSE			New York Stock Exchange
OAH			Office of Administrative Hearings
OCC			Oklahoma Corporation Commission
Offering			MEP initial public offering
OLP			Enbridge Energy, Limited Partnership, also referred to as the Lakehead Partnership
OPA			Oil Pollution Act
OTC			Over-the-counter
PADD			Petroleum Administration for Defense Districts
PADD II			Consists of Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin
PADD III			Consists of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas
PADD IV			Consists of Colorado, Idaho, Montana, Utah and Wyoming
PADD V			Consists of Alaska, Arizona, California, Hawaii, Nevada, Oregon and Washington

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Partnership Agreement			Seventh Amended and Restated Agreement of Limited Partnership of Enbridge Energy Partners, L.P., also referred to as our partnership agreement
Partnership			Enbridge Energy Partners, L.P. and its consolidated subsidiaries
PHMSA			Pipeline and Hazardous Materials Safety Administration
PIPES Act of 2016			Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016
Ppb			Parts per billion
PPI-FG			Producer Price Index for Finished Goods
PSA			Pipeline Safety Act of 1992
PSOP			Performance Stock Option Plan (2007	)
PSUP			Performance Stock Unit Plan (2007	)
ROE			Return on Equity
RSUP			Restricted Stock Unit Plan (2006	)
SAGD			Steam assisted gravity drainage
S&P			Standard & Poor’s
SEC			United States Securities and Exchange Commission
Series AC interests			Partnership interests of the OLP related to all the assets, liabilities and operations of the Alberta Clipper Pipeline
Series EA interests			Partnership interests of the OLP related to all the assets, liabilities and operations of the Eastern Access Projects
Series LH interests			Partnership interests of the OLP related to all the assets, liabilities and operations of the Lakehead System, excluding those designated by the Series AC interests
Series ME interests			Partnership interests of the OLP related to all the assets, liabilities and operations of the U.S. Mainline Expansion projects
Southern Access			Southern Access Pipeline, a 42-inch pipeline that runs from Superior, Wisconsin to Flanagan, Illinois on our Lakehead system
STIP			Short-term incentive plan
Tariff Agreement			A 1998 offer of settlement filed with the FERC
TRRC			Texas Railroad Commission
TSA			Transportation Services Agreement
TSX			Toronto Stock Exchange
UBTI			Unrelated Business Taxable Income
U.S. GAAP			United States Generally Accepted Accounting Principles
U.S. Mainline Expansion projects			Multiple projects that will expand access to new markets in North America for growing production from western Canada and the Bakken Formation
VIEs			Variable interest entities
VOC			Volatile Organic Compound
WCSB			Western Canadian Sedimentary Basin
Williston			Williston Basin Pipeline LLC
WOTUS			Waters of the United States

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PART I

Item 1. Business

OVERVIEW

We are a publicly traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets, and natural gas gathering, treating, processing, transportation and marketing assets in the United States of America. Our Class A common units are traded on the New York Stock Exchange, or NYSE, under the symbol “EEP.”

The following chart shows our organization and ownership structure as of December 31, 2016. The ownership percentages referred to below illustrate the relationships between us, Enbridge Energy Management, L.L.C., or Enbridge Management, Enbridge Energy Company, Inc., or our General Partner, and Enbridge Inc., or Enbridge, and its affiliates:

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We were formed in 1991 by our General Partner, initially to own and operate the Lakehead system, which is the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada, referred to as the Mainline system. A subsidiary of Enbridge owns the Canadian portion of the Mainline system. Enbridge is a leading provider of energy transportation, distribution and related services in North America and internationally. Enbridge is the ultimate parent of our General Partner.

Enbridge Management is a Delaware limited liability company that was formed in May 2002 to manage our business and affairs. Under a delegation of control agreement, our General Partner delegated substantially all of its power and authority to manage our business and affairs to Enbridge Management. Our General Partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management. Enbridge Management is the sole owner of i-units.

BUSINESS STRATEGY

Our primary objective is to provide stable, growing and sustainable cash distributions to our unit holders, while maintaining a relatively low-risk investment profile. Our business strategies focus on creating value for our customers, which we believe is the key to creating value for our investors. To accomplish our objective, we focus on the following key strategies:

We will continue to focus on safety, environmental integrity, innovation and effective stakeholder relations. We strive to operate our existing infrastructure to provide flexibility for our customers and ensure system capacity is reliable and available when required.

We intend to develop energy transportation assets and related facilities that are complementary to our existing systems. This will be achieved primarily through organic growth. Our core businesses provide plentiful opportunities to achieve our primary business objectives. We may also expand our core asset platforms through purchase of assets from Enbridge or third parties.

Our Major Projects group is committed to executing and completing projects safely, on time and on budget. These include expansions or extensions of our existing infrastructure.

We plan to develop and acquire new assets to meet customer needs by expanding capacity into new markets with favorable supply and demand fundamentals. This includes the potential of purchasing additional assets from Enbridge or third parties.

Our current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses while remaining focused on the safe, reliable, effective and efficient operation of our current assets. We may pursue accretive acquisitions in or near the areas in which we have a competitive advantage. We intend to execute our growth strategy by maintaining a capital structure that balances our outstanding debt and equity in a manner that sustains our investment grade credit rating.

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Liquids

The map below presents the locations of our current Liquids systems’ assets and projects being constructed. The map also depicts some Liquids Pipelines assets owned by other Enbridge affiliates and projects being constructed to provide an understanding of how they interconnect with our Liquids systems.

The following discussion provides an overview of North American production that is transported on our pipelines and the projects that we are pursuing to connect the growing supplies of this production to key refinery markets in the United States.

In 2016, we transported production from the Western Canadian Sedimentary Basin, or WCSB, and the North Dakota Bakken formation. Western Canadian crude oil is an important source of supply for the United States. According to the latest available data for 2016 from the United States Department of Energy’s, or DOE, Energy Information Administration, or EIA, Canada supplied approximately 3.2 million barrels per day, or Bpd, of crude oil to the United States, the largest source of United States imports. Over half of the Canadian crude oil moving into the United States was transported on the Enbridge Mainline system. The Canadian Association of Petroleum Producers, or CAPP, forecasted as of June 2016 that future production from the Alberta oil sands will continue to experience steady growth during the next two decades with an additional 1.3 million Bpd of production by 2030, based on a subset of currently approved applications and announced expansions. We are well positioned to deliver growing volumes of crude oil that are expected from the WCSB to our existing as well as new markets.

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North Dakota, Montana and Saskatchewan, Canada saw a leveling off in the development of crude oil, natural gas, and NGLs from the Bakken and Three Forks formations. The latest data released in 2013 by the United States Geological Survey estimates that technically recoverable oil in the Bakken and Three Forks formation in North Dakota is approximately 7.4 billion barrels.

Along with Enbridge, we are actively working with our customers to develop transportation options that will alleviate capacity constraints in addition to providing access to new markets in the United States. Our market strategy is to provide safe, timely, economic, competitive and integrated transportation solutions to connect growing supplies of North American crude oil production to key refinery markets in the United States and Canada. Together, our existing and future plans advance our vision of being the leading energy delivery company in North America. In addition to this vision, we have advanced our Operational Risk Management Program. It includes a state-of-the-art Liquids Pipelines control center and the most extensive maintenance, integrity and inspection program in the history of the North American pipeline industry, with 1,105 in-line inspections and 14,237 pipeline integrity verification digs completed by Enbridge and us from 2010 through 2016.

We have a multi-billion dollar growth program underway, with projects coming into service through 2019 in addition to options to increase our economic interest in projects that are jointly funded by us and Enbridge. This growth program includes expansions to our Mainline system as well as replacement of the Line 3 pipeline to ensure WCSB production has efficient and reliable access to markets in the U.S. Midwest and beyond. In addition, in February 2017, we completed the acquisition of an effective 27.6% equity interest in the Bakken Pipeline System through our joint venture with Marathon Petroleum Corporation, or MPC. This system, upon completion, will further enhance our strategy of providing efficient market access solutions for Bakken production while providing the opportunity for the implementation of joint tolls with the Energy Transfer Crude Oil Pipeline, or ETCOP, and will also enhance market access opportunities for our customers and create a new flow path through the Mainline system to the eastern U.S. Gulf Coast. Refer to Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Future Prospects Update for Liquids for further details.

Furthermore, while the Line 3 Replacement Program will not provide an increase in the overall capacity of the mainline system but will restore approximately 370,000 Bpd and supports the safety and operational reliability of the system, enhances flexibility and will allow us and Enbridge to optimize throughput from Western Canada into Superior, Wisconsin. This project, along with the other projects on the Mainline, will provide increased market access for producers to refineries in the United States upper-Midwest, Eastern Canada, and the United States Gulf Coast refining centers. For further details regarding our projects, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations — By Segment.

Natural Gas

The map below presents the locations of our current Natural Gas systems assets. These assets are owned by Midcoast Energy Partners, L.P., or MEP, and its subsidiaries. MEP is a Delaware limited partnership we formed to serve as our primary vehicle for owning and growing our natural gas and NGL midstream business in the United States. MEP completed its initial public offering, or the Offering, in November of 2013, but we continue to own all of the equity interests in MEP’s general partner, a 51.9% limited partner interest in MEP and a 48.4% limited partner interest in MEP’s operating subsidiary, Midcoast Operating.

On January 27, 2017, MEP announced that it entered into a definitive merger agreement with our General Partner, whereby our General Partner will acquire, for cash, subject to the terms and conditions thereof, all of the outstanding publicly held common units of MEP at a price of $8.00 per common unit for an aggregate transaction value of $170.2 million. Subject to certain conditions, the transaction is expected to close in the second quarter of 2017. Upon closing, MEP will cease to be a publicly traded partnership. The transaction arises from the strategic alternatives review process, announced on May 2, 2016.

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This map depicts some assets owned or under development by Enbridge to provide an understanding of how they relate to our Natural Gas systems.

Our natural gas assets are primarily located in Texas and Oklahoma, a region which continues to see limited drilling activity as a result of extended commodity pricing challenges. These core basins are known as the East Texas basin, the Fort Worth basin and the Anadarko basin. Our focus has primarily been on developing and expanding the service capability of our existing pipeline systems and acquiring assets with strong growth prospects located in or near the areas we serve or have competitive advantage. Our Natural Gas business also includes rail and liquids marketing operations that we use to enhance the value of the NGLs produced at our processing plants.

The operations and commercial activities of our gathering and processing assets and intrastate pipelines are integrated to provide better service to our customers. From an operations perspective, our key strategies are to provide safe and reliable service at reasonable costs to our customers and capitalize on opportunities for attracting new customers. From a commercial perspective, our focus is to provide our customers with a greater value for their commodity. We intend to achieve this latter objective by increasing customer access to preferred markets for natural gas and NGLs. The aim is to be able to move significant quantities of natural gas and NGLs from our Anadarko, North Texas and East Texas systems to the major market hubs in Texas and Louisiana. From these market hubs, natural gas can be used in the local Texas markets or transported to consumers in the Midwest, Northeast and Southeast United States. The primary market hub for NGLs is the fractionation center in Mont Belvieu, Texas, with its access to refineries, petro-chemical plants, export terminals and outbound pipelines.

The long term prospects in our core areas remain favorable, primarily as a result of technological advancements that have enhanced production of natural gas and NGLs from tight sand and shale formations. The reserves and resource potential in all three of our operating basins is substantial. The extended low price environment has forced producers to be more selective in their drilling efforts, with many producers high-grading well selection to the core portion of production areas. When and if natural gas and NGL prices recover to the level that will incentivize producers to drill their lean gas and NGL prospects, our core assets are well positioned to gather, treat and transport this gas to market. Our goal is to offer our customers the ability to gather, process, and transport their liquids to major markets.

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BUSINESS SEGMENTS

We conduct our business through two business segments: Liquids and Natural Gas. These segments have unique business activities that require different operating strategies. For information relating to revenues from external customers, operating income and total assets for each segment, refer to Part II, Item 8. Financial Statements and Supplementary Data, Note 5. Segment Information.

Liquids Segment

Our Liquids segment includes the operations of our Lakehead, North Dakota and Mid-Continent systems. The following table provides selected information regarding our Liquids systems:

		Pipeline Length (miles)				Storage Tanks				Storage Capacity (million barrels)(1)				Pump Stations
Lakehead			5,022				77				18.1				75
Mid-Continent			433				109				25.1				13
North Dakota			660				25				1.8				20
Total			6,115				211				45.0				108

Lakehead system

Our Lakehead system, together with the Enbridge system in Canada, form the Mainline system, which has been in operation for over 60 years and forms the longest liquid petroleum pipeline system in the world. The Mainline system operates in a segregated, or batch, mode allowing the transportation of over 30 crude oil commodities typically classified as light, medium, or heavy crude oil, condensate, and NGLs. The Mainline system serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the provinces of Ontario and Quebec, Canada. The Lakehead system is the U.S. portion of the Mainline system. It is an interstate common carrier pipeline system regulated by the FERC, and is the primary transporter of crude oil and liquid petroleum from Western Canada to the United States.

Over the past seven years, we have completed the largest pipeline expansion program in our history in order to accommodate the growing upstream supply that will feed our completed downstream market access projects. Our customers have long development timelines and need assurance that adequate pipeline infrastructure will be in place in time to transport the additional production resulting from completion of their projects. The projects included in our Eastern Access, Light Oil Market Access, U.S. Gulf Coast access, and associated Mainline/Lakehead expansion initiatives will provide the needed incremental market access for both our producer and refiner customers located in our primary target markets.

Our Lakehead system is strategically interconnected to multiple refining centers and transportation hubs located within Petroleum Administration for Defense Districts, or PADD II, such as: Chicago, Illinois; Patoka, Illinois; and Cushing, Oklahoma. In addition, we are also strategically connected to the largest U.S. refining center in the U.S. Gulf Coast through other pipelines owned by Enbridge and its affiliates. WCSB production in excess of Western Canadian demand moves on existing pipelines into primarily PADD II, with secondary markets including: the U.S. Gulf Coast (PADD III); the Rocky Mountain states (PADD IV); the Anacortes area of Washington state (PADD V); and to Eastern Canada (Ontario and Quebec).The Lakehead system mainly serves the PADD II market directly and the PADD III market indirectly. Bakken production in excess of local demand primarily moves on existing pipelines into PADD II or is transported by rail to coastal Canadian and U.S. refining markets. The U.S. Gulf Coast continues to be an attractive market for WCSB producers due to the market’s large refining capacity designed to process heavy crude oil. The forecasted long-term incremental growth of Canadian oil sands and Bakken production provides stability for existing pipeline throughputs to historical markets as well as creating new growth opportunities available to both us and our competitors.

Customers.  Our Lakehead system operates under month-to-month transportation arrangements with our shippers. During 2016, approximately 38 shippers tendered crude oil and liquid petroleum for delivery through our Lakehead system. We consider multiple companies that are controlled by a common entity to be a single shipper for purposes of determining the number of shippers delivering crude oil and liquid petroleum on our Lakehead system. Our customers include integrated oil companies, major independent oil producers, refiners and marketers.

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Supply and Demand.  Our Lakehead system is part of the longest crude oil pipeline in the world and is a critical component of the North American crude oil supply pipeline network. Lakehead is well positioned as the primary transporter of Western Canadian crude oil and continues to benefit from past and anticipated future crude oil production growth from the Alberta Oil Sands, as well as recent development in tight oil production in North Dakota. Aside from the receipt locations on the Mainline system within Canada, our Lakehead system receives injections from locations within the United States. Clearbrook, Minnesota is the receipt location for U.S. Bakken production, and other U.S. sources are received at Lewiston, Michigan and Mokena, Illinois.

Crude oil originating from the WCSB comprises the majority of Lakehead system deliveries. According to the Energy Information Administration, or EIA, Canada is currently ranked third in the world for total proved reserves, just behind Venezuela and Saudi Arabia, respectively. The NEB estimates that 97% of Canada’s total proved reserves are attributed to Alberta’s oil sands bitumen, with the remainder being conventional oil sources. The Alberta Energy Regulator, or AER, estimates 166.8 billion total barrels, or approximately 165 billion and 1.8 billion barrels of established proved bitumen and conventional reserves, respectively, remain for the region as of 2016. The NEB estimates that total production from the WCSB averaged approximately 3.6 million Bpd in 2016 and 3.7 million in 2015. Furthermore, these production levels are expected to grow in the future, as previously discussed.

The growth forecast in the oil sands will be primarily driven by steam assisted gravity drainage, or SAGD, projects in the long-term. Mining projects are the main contributor to near-term growth, with other development projects on hold until prices recover and well economics improve. Based on projects currently under construction in Western Canada, the incremental productive capacity that would have access to our systems is reported to increase over the next three years by approximately 450,000 Bpd.

Lakehead throughput volumes are primarily supplied by crude oil produced in the Canadian oil sands and Bakken resource plays. North Dakota’s Bakken/Three Forks resource play has become a major component of United States domestic supply. By 2014, crude oil supply from the region had grown to over 1.2 million Bpd, but has since retracted in response to the low price environment. In 2016, production averaged one million Bpd and is expected to remain at that level through 2017. Forecasts of Western Canadian crude oil supply are periodically completed by Enbridge, CAPP and the NEB, among others. The June 2016 CAPP forecast predicts Western Canada oil sands production is expected to grow by 1.3 million Bpd to over 3.7 million Bpd by 2030. This compares with an expected decrease of 80,000 Bpd from conventional production sources over the same time frame. CAPP revised its oil sands production forecast downward by 285,000 Bpd in 2016 from 4.0 million Bpd to 3.7 million Bpd due to the low oil price environment and constraints arising from oil sands cost competitiveness and delays in project schedules. Despite the revisions, the production growth forecasted out of our primary supply markets requires additional pipeline capacity.

PADD II is the primary demand market for our Lakehead system. Deliveries on our Lakehead system are negatively affected by periodic maintenance, other competitive transportation alternatives, or refinery turnarounds and other shutdowns at producing plants that supply crude oil. Based on growth in Western Canadian and Bakken crude oil supply and Lakehead operational performance improvements, deliveries on our Lakehead system are expected to grow beyond the 2.6 million Bpd of actual deliveries experienced during 2016.

The latest data available from the EIA shows that total PADD II demand was 3.6 million Bpd. PADD II produced 1.7 million Bpd and imported 2.2 million Bpd from Canada and other regions located in the United States, with exports comprising the remaining difference between PADD II supply and demand. Imports from Canada comprised 98% of total PADD II crude oil imports, with approximately 65% or 1.4 million Bpd transported on our Lakehead system. The remaining barrels were imported via competitor pipelines from Alberta and offshore sources via the U.S. Gulf Coast or regional transfers from PADD III or PADD IV.

Lakehead system deliveries for 2016 were approximately 259,000 Bpd higher than delivery volumes for 2015. Total deliveries from our Lakehead system averaged 2.6 million Bpd in 2016, meeting approximately 71% of the refinery capacity in the greater Chicago area; 78% of the Minnesota refinery capacity; and 77% of Ontario refinery capacity. Refinery configurations and crude oil requirements within PADD II continue to create an attractive market for Western Canadian and Bakken supply. However, Crude oil demand in PADD II averaged 3.6 million Bpd, an increase of only 73,000 Bpd from 2015. Moreover, overall refining utilization remained relatively flat in 2016 at 92%.

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Competition.  WCSB crude oil competes with local and imported crude oil. Of all the pipeline systems that transport crude oil out of Canada, the Mainline system transported approximately half of all Canadian crude oil imports into the United States in 2016.

Our Eastern Access, Light Oil Market Access, U.S. Gulf Coast Access, and associated Mainline expansion projects will improve the flexibility of our system and are designed to increase Lakehead throughput by reaching new markets. Given the expected increase in crude oil production from the Alberta Oil Sands over the next 10 years, alternative transportation proposals have been presented to crude oil producers. Competitors’ proposals to WCSB and Bakken shippers include expanding, twinning, extending and building new pipeline assets. These proposals and projects are in various stages of regulatory approval.

Transportation of crude oil by rail has also emerged as a competitor primarily due to the lack of pipeline capacity for the WCSB and Bakken regions. As a result, a significant amount of rail loading capacity has been constructed and is proposed in both markets. Rail transportation becomes less competitive, however, as crude oil price differentials narrow between key markets due to high transportation costs relative to cost of transportation by pipeline.

These competing alternatives for delivering Western Canadian crude oil into the United States and other markets could erode shipper support for further expansion of our Lakehead system. Accordingly, competition could also impact throughput on and utilization of the Mainline system. The Mainline system, however, offers significant cost savings and flexibility to shippers.

Deliveries for our Lakehead system over the past five years were as follows:

		2016				2015				2014				2013				2012
		(thousands of Bpd)
United States
Light crude oil			492				500				496				473				521
Medium and heavy crude oil			1,471				1,364				1,167				948				879
NGL			5				5				6				6				5
Total United States			1,968				1,869				1,669				1,427				1,405
Canada
Light crude oil			427				294				298				247				228
Medium and heavy crude oil			100				77				72				76				85
NGL			79				75				74				66				72
Total Canada			606				446				444				389				385
Total Deliveries			2,574				2,315				2,113				1,816				1,790
Barrel miles (billions per year)			724				640				582				487				480

Mid-Continent system

Our Mid-Continent system, which we have owned since 2004, is located within PADD II and is comprised of our Ozark pipeline and storage terminals at Cushing, Oklahoma. Our Ozark pipeline transports crude oil from Cushing, Oklahoma to Wood River, Illinois, where it delivers to the WRB refinery, a joint venture between Cenovus Energy and Phillips 66 located at Wood River, and interconnects with the Woodpat Pipeline and the Wood River Pipeline, each owned by unrelated parties.

In December 2016, we entered into an agreement to sell the Ozark pipeline system to a subsidiary of MPLX LP for cash proceeds of approximately $209.0 million plus an estimated $10.2 million in reimbursable capital costs up to the closing date of the transaction. Subject to certain pre-closing conditions, the transaction is expected to close by the end of the first quarter of 2017. For more information, refer to Item 8. Financial Statements and Supplementary Data, Note 11. Property, Plant and Equipment.

The storage terminals consist of 109 individual storage tanks ranging in size from 78,000 to 570,000 barrels. Of the approximately 25.1 million barrels of storage shell capacity on our Mid-Continent system, the Cushing terminal accounts for approximately 19.7 million barrels. A portion of the storage facilities are used for operational purposes, while we contract the remainder of the facilities with various crude oil market participants for their term storage requirements. Contract fees include fixed monthly capacity fees as well as utilization fees, which we charge for injecting crude oil into and withdrawing crude oil from the storage facilities.

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Customers.  Our Mid-Continent system operates under month-to-month transportation arrangements as well as long-term and short-term storage arrangements with shippers. During 2016, approximately 45 shippers tendered crude oil for service on our Mid-Continent system. We consider multiple companies that are controlled by a common entity to be a single shipper for purposes of determining the number of shippers delivering crude oil and liquid petroleum on our Mid-Continent system. These customers include integrated oil companies, independent oil producers, refiners and marketers.

Supply and Demand.  Our Mid-Continent system is positioned to capitalize on increasing demand for both domestic and imported crude oil, specifically Canadian imports into the United States. Our Ozark pipeline system currently serves an exclusive corridor between Cushing, Oklahoma and Wood River, Illinois, delivering crude commodities with low viscosities and sulfur content at more competitive prices than similar commodities accessible from other sources. In 2016, PADD II imported 2.2 million Bpd of foreign crude oil, the majority of which were imported from Canada primarily on our Lakehead system. The remaining barrels of crude oil were imported from PADDs III and IV as well as offshore sources. We expect the demand for local supply to increase and the demand for Canadian crude to stay strong, thus displacing the necessity for other foreign sources. Our Ozark system continued to be highly utilized in 2016, although average deliveries on the Ozark pipeline system were 188,000 Bpd for 2016 down from 212,000 Bpd for 2015.

Demand for storage capacity at Cushing, Oklahoma has remained high as customers continue to value the flexibility and optionality available with this service as well as the superior connectivity that our terminal offers. Our storage terminals rely on demand for storage service from numerous oil market participants. Producers, refiners, marketers and traders value our storage capacity in Cushing, Oklahoma for a number of different reasons, including batch scheduling, stream quality control, inventory management, and speculative trading opportunities.

Competition.  As previously mentioned, our Ozark pipeline system currently serves an exclusive corridor between Cushing, Oklahoma and Wood River, Illinois. However, refineries connected to Wood River, Illinois have crude oil supply options available from Canada via our Lakehead system as well as third-party pipelines. These same refineries also have access to the United States Gulf Coast and foreign crude oil supply through a third-party pipeline system, which is an undivided joint interest pipeline that is owned by unrelated parties. In addition, refineries located east of Patoka, Illinois with access to crude oil through our Ozark system also have access to west Texas supply from the Permian Basin through the West Texas Gulf/Mid-Valley Pipeline systems owned by unrelated parties. Our Ozark pipeline system faces competition from a competitor’s pipeline from Hardisty, Alberta to Patoka, Illinois.

Furthermore, the anticipated completion of the Dakota Access Pipeline in 2017 will enable the delivery of crude oil similar to the crude oil currently delivered by our Ozark pipeline, increasing pipeline competition into the refining markets currently served by the Ozark pipeline and impacting Ozark’s current competitive advantages. Through our joint venture with MPC, on February 15, 2017 we acquired a minority interest in the Bakken Pipeline system, which includes the Dakota Access Pipeline. Refer to Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments for further details.

Competitors to our storage facilities at Cushing, Oklahoma include large integrated oil companies, private entities and other midstream energy partnerships. Many of these competitors have the capability to expand in the future and better compete on quality of service, reliability, increased connectivity and price.

North Dakota system

Our North Dakota system is a crude oil gathering and interstate pipeline transportation system servicing the Williston Basin in North Dakota and Montana, which includes the highly publicized Bakken and Three Forks formations. The gathering pipelines that comprise our North Dakota system collect crude oil from nearly 80 different receipt facilities located throughout western North Dakota, including nearly 20 third party gathering pipeline connections, and deliver a fungible common stream to a variety of interconnecting pipeline and rail export facilities.

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Traditionally, the majority of our pipeline deliveries have been made into interconnecting pipelines at Clearbrook, Minnesota where two other pipelines originate: (1) a third-party pipeline serving St. Paul, Minnesota refinery markets; and (2) our Lakehead system providing further pipeline transportation on the Enbridge system into the Great Lakes, eastern Canada and U.S. Midwest refinery markets that include Cushing, Oklahoma, Patoka, Illinois, and other pipelines delivering crude oil to the U.S. Gulf Coast. We have significantly increased the pipeline capacity of our North Dakota system through a series of projects in recent years while continuing to serve the system’s traditional markets in order to provide an array of market options and services.

Customers.  Customers of our North Dakota system include refiners of crude oil, producers of crude oil and purchasers of crude oil at the wellhead, such as marketers, that require crude oil gathering and transportation services. Producers range in size from small independent owner/operators to large integrated oil companies. During 2016, approximately 246 shippers tendered crude oil for service on our North Dakota system.

Supply and Demand.  Similar to our Lakehead system, our North Dakota system depends upon demand for crude oil in the Great Lakes and Midwest regions of the United States and the ability of crude oil producers to maintain their crude oil production and exploration activities. The state of North Dakota reported production levels of 1.0 million Bpd as of November 2016 with projections remaining at that level through 2017.

Competition.  Due to the growth in production from these formations over the last several years, competition has increased substantially. Traditional competitors of our North Dakota system include refiners, integrated oil companies, interstate and intrastate pipelines or their affiliates and other crude oil gatherers. Many crude oil producers in the oil fields served by our North Dakota system have alternative gathering facilities available to them or have the ability to build their own assets, including their own rail loading facilities.

Currently, the primary competition to our North Dakota system is rail. Initially considered a niche or alternative form of transportation, rail currently represents about 30% of the total Bakken crude exported from North Dakota.

There are also a number of third-party pipelines with proposed expansions to increase capacity and take advantage of the Bakken and Three Forks volume growth. Many of these third party pipeline projects include pipeline connections into our North Dakota system as part of their project scope. As discussed above, through our joint venture with MPC we own a minority stake in the Bakken Pipeline System. As pipeline expansion projects create more export capacity from the Bakken and other pipeline projects provide increased access to more refinery markets across the United States, we expect North Dakota customers will shift volumes back to pipelines.

Natural Gas Segment

Our natural gas business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility, as well as rail and liquids marketing operations. 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, using the Texas Express NGL system, we gather NGLs from certain of our facilities for delivery on the Texas Express NGL mainline to Mont Belvieu, Texas.

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The following table provides selected information regarding our natural gas and NGL systems in our natural gas business:

		Natural gas gathering and transportation pipelines (length in miles)				NGL pipelines (length in miles)				Number of active natural gas processing plants				Number of standby natural gas processing plants				Number of active natural gas treating plants				Number of standby natural gas treating plants
Anadarko system			3,100				89				5				7				—				1
East Texas system(1)			4,000				177				6				1				4				5
North Texas system			3,700				16				4				2				—				—
Total			10,800				282				15				10				4				6
Texas Express NGL system(2)			—				709	(3)			—				—				—				—

Anadarko System

Our Anadarko system includes production from the Granite Wash tight sand formation. Productive horizons in the Granite Wash play include the Hogshooter, Checkerboard, Cleveland, Skinner, Red Fork, Atoka and Morrow formations. Recent decreases in NGL and condensate prices have resulted in decreased activity in the region. The Anadarko basin wells generally have long lives with predictable flow rates. Producers generally pursue wells with higher condensate and oil production relative to historical activity that was focused on natural gas and NGL prospects.

With recent commodity prices in extended decline resulting in reduced production, we have idled approximately seven of our less efficient processing plants and consolidated volumes to our more efficient plants. These plants are available for restart when production increases.

Our Anadarko system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the Mid-Continent and Gulf Coast regions of the United States. NGLs produced at our Anadarko system processing plants are transported by pipeline to third-party fractionation facilities and NGL market hubs in Conway, Kansas and Mont Belvieu, Texas.

East Texas System

Our East Texas system gathers production from: the Cotton Valley, James Lime and lean Bossier Shale plays, which are located on the western side of our East Texas system; the Haynesville/Bossier Shale plays, which run from western Louisiana into East Texas and are among the largest natural gas resources in the United States; and the Cotton Valley Sand formation, which also runs from western Louisiana into East Texas and has a high content of NGLs and condensate on the eastern side of our East Texas system. The East Texas basin also includes multiple other natural gas and oil formations that are frequently explored, including among others, the Woodbine, Travis Peak, Rodessa, and Pettite. The East Texas wells generally have long lives with predictable flow rates.

In May 2015, we placed into service a cryogenic natural gas processing plant near Beckville in Panola County, Texas, which we refer to as the Beckville Processing Plant. This plant serves existing and prospective customers pursuing production in the Cotton Valley formation, which is comprised of approximately ten counties in East Texas. Our Beckville processing plant is capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs to accommodate the additional liquids-rich natural gas within this geographical area in which our East Texas system operates. Related NGL takeaway infrastructure connecting the Beckville plant to third-party NGL transportation systems was also constructed. In 2016, our processing plants in East Texas were near or at full capacity.

Our East Texas system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the United States Gulf Coast, as well as to several wholesale customers. 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 transported by pipeline to Mont Belvieu, Texas for fractionation.

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North Texas System

A substantial portion of natural gas on our North Texas system is produced in the Barnett Shale play within the Fort Worth basin. The North Texas wells are located in the Fort Worth basin and generally have long lives with predictable flow rates. As producers have shifted to more economic advantaged basins, we have seen our natural gas volumes decline in this basin.

Our North Texas system has numerous market outlets for the natural gas that we gather and process and NGLs that we recover on our system. We have connections to major intrastate transportation pipelines that connect our facilities to market centers in the Dallas-Fort Worth area.

Texas Express NGL System

The Texas Express NGL system consists of an NGL gathering system and an NGL intrastate mainline transportation pipeline that originates in Skellytown, Texas and extends to NGL fractionation and storage facilities located in Mont Belvieu, Texas. Volumes from the Rockies, Permian basin and Mid-Continent regions are delivered to the Texas Express NGL system utilizing the Mid-America Pipeline between the Conway hub and the Hobbs NGL fractionation facility in West Texas, both of which are owned by a third party. In addition, volumes from the Denver-Julesburg basin in Weld County, Colorado can access the system through the Front Range Pipeline which is also owned by third parties.

Customers.  Our natural gas business serves customers predominantly in the Gulf Coast region of the United States and includes both upstream customers and purchasers of natural gas and NGLs. Upstream customers served by our systems primarily consist of small, medium and large independent operators and large integrated energy companies, while our natural gas sales customers primarily consist of large users of natural gas, such as power plants, industrial facilities, local distribution companies and other large consumers. Our condensate and NGLs are marketed to chemical facilities, refiners, various third parties and end users. Due to the cost of making physical connections from the wellhead to gathering systems, the majority of our customers tend to renew their gathering and processing contracts with us rather than seeking alternative gathering and processing services.

Supply and Demand.  Demand for our gathering, processing and transportation services primarily depends upon the supply of natural gas reserves and associated natural gas crude oil development and the drilling rate for new wells. The level of impurities in the natural gas gathered also affects treating services. All of our natural gas systems exist in regions that have shale or tight sands formations where hydraulic fracturing technology can be utilized to increase production from the natural gas wells. Demand for these services depends upon overall economic conditions, drilling activity and the prices of natural gas, NGLs, and condensates. Commodity prices for natural gas, NGLs, and condensates remained low throughout 2016. As a result, there has been reduction in drilling activity by producers and reduced volumes on the systems we operate. Our existing systems are located in basins that have the opportunity to grow in an improved pricing environment.

Competition.  Competition in our natural gas business is significant in all of the markets we serve. Competitors include interstate and intrastate pipelines or their affiliates and other midstream businesses that gather, treat, process and market natural gas or NGLs. Our gathering business’s principal competitors are other midstream companies and, to a lesser extent, producer-owned gathering systems. Some of these competitors are substantially larger than we are. Because pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipeline companies. Pipelines typically compete with each other based on location, capacity, price and reliability.

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. Many of the large wholesale customers we serve have multiple pipelines connected or adjacent to their facilities. Accordingly, many of these customers have the ability to purchase natural gas directly from a number of pipelines or third parties that may hold capacity on the various pipelines. In addition, several new interstate natural gas pipelines have been constructed in areas currently served by our natural gas transportation pipelines. Some of these new pipelines may compete for customers with our existing pipelines.

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Marketing Operations

The primary role of our marketing business is to provide marketing services of natural gas, NGLs and condensate. We purchase and receive natural gas, NGLs and other products from pipeline systems and processing plants, including those owned by us, and sell and deliver them to wholesale customers, distributors, refiners, fractionators, chemical facilities, various third parties and end users. A majority of the natural gas and NGLs we purchase are produced in Texas markets where we have expanded interstate deliverability alternatives over the past several years. We can use our connectivity to interstate pipelines to improve value for the producers by delivering natural gas into premium markets and NGLs to primary markets where we sell them to major customers. Additionally, our marketing business derives operating income from providing logistics services for our customers from the wellhead to markets.

On August 15, 2016, our NGL Logistics and Marketing business, ELTM, sold its transport trucks and trailers (alternatively “our trucking business”) to a third party. In conjunction with the sale ELTM entered into a long-term trucking services agreement with the purchaser, insuring no interruption of our logistics activities.

As of December 31, 2016, the physical assets of our marketing business primarily consist of:

We also enter into agreements with various third parties to obtain NGL supply, transportation, gas balancing, fractionation and storage capacity in support of the marketing services provided. These agreements supply us with the following:

Customers.  Most of our customers are wholesale customers, refiners and petrochemical producers, fractionators, propane distributors and industrial, utility and power plant customers. In addition, we sell natural gas and NGLs to marketing companies at various market hubs.

Supply and Demand.  Supply for our marketing business depends to a large extent on the natural gas reserves, associated natural gas from crude oil development and rate of drilling within the areas served by our gathering, processing and transportation business. Demand is typically driven by a number of factors such as physical domestic and international industrial requirements.

Since major market hubs for natural gas, NGLs and related products are located in the Mid-Continent and Gulf Coast regions of the United States and our marketing assets are geographically located within Texas, Louisiana, Oklahoma and Mississippi, the majority of activities are conducted within those states. Our interconnected gathering and transportation systems and our long-term trucking and railcar arrangements mitigate the risk that our natural gas and NGLs will be shut in by capacity constraints on downstream NGL pipelines and other facilities.

One of the key components of our marketing business is our natural gas and NGL purchase and resale activities. Through our natural gas and NGL purchase and resale services, we can efficiently manage the transportation and delivery of natural gas from our gathering, processing and transportation systems and deliver them to on-system industrial plant customers, and NGLs to marketing companies at various market hubs. We typically price our sales based on multiple published daily or monthly price indices. In addition, sales to wholesale customers include a pass-through charge for costs of transportation and additional margin to compensate us for the associated services we provide.

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We also use third-party storage facilities and pipelines for the right to store NGLs for various periods of time to mitigate risk associated with sales and purchase contracts. We have also entered into multiple long-term fractionation contracts with third-party fractionators to provide access to fractionation capacity for our customers.

Competition.  Our marketing operations have 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.

Seasonality

The drilling activities of producers within our areas of operations generally do not vary materially by season but may be affected by adverse weather. Generally, the demand for natural gas and NGLs decreases during the spring and fall months and increases during the winter months and, in some areas, during the summer months. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. Demand for natural gas with respect to power plant customers is typically driven by weather-related factors.

REGULATION

Regulation by the FERC of Interstate Common Carrier Liquids Pipelines

The FERC regulates the interstate pipeline transportation of crude oil, petroleum products, and other liquids such as NGLs. Our Lakehead, North Dakota, Bakken and Ozark systems are our primary interstate common carrier liquids pipelines subject to regulation by the FERC under the Interstate Commerce Act, or ICA, the Energy Policy Act of 1992, or EP Act, and rules and orders promulgated thereunder. As common carriers in interstate commerce, these pipelines provide service to any shipper who makes a reasonable request for transportation services, provided that the shipper satisfies the conditions and specifications contained in the applicable tariff. The ICA requires us to maintain tariffs on file with the FERC that set forth the rates we charge for providing transportation services on our interstate common carrier pipelines, as well as the rules and regulations governing these services.

The ICA gives the FERC the authority to regulate the rates we can charge for service on interstate common carrier pipelines. The ICA requires, among other things, that such rates be “just and reasonable” and that they not be unduly discriminatory or unduly preferential to certain shippers. The ICA permits interested parties to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate the rates to determine if they are just and reasonable. If the FERC finds the new or changed rate unlawful, it is authorized to require the carrier to refund, with interest, the amount of any revenues in excess of the amount that would have been collected during the term of the investigation at the rate properly determined to be lawful. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

In October 1992, Congress passed the EP Act, which deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment, or that were in effect on the 365^th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period, to be just and reasonable under the ICA (i.e., “grandfathered”). The EP Act also limited the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party must show: (1) that it was contractually barred from challenging the rates during the relevant 365-day period; (2) that there has been a substantial change after the date of enactment of the EP Act in the economic circumstances of the pipeline or in the nature of the services that were the basis for the rate, or (3) that the rate is unduly discriminatory or unduly preferential.

The FERC determined our Lakehead system rates are not covered by the grandfathering provisions of the EP Act because they were subject to challenge prior to the effective date of the statute. The rates for our North Dakota and Ozark systems in effect at the time of the EP Act should be found to be subject to the grandfathering provisions of the EP Act because those rates were not suspended or subject to protest or complaint during the 365-day period established by the EP Act.

The EP Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561 which adopted an indexing rate methodology for petroleum pipelines. Under these regulations, which became effective January 1, 1995, petroleum pipelines are able to change

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their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made within the ceiling levels may be protested, but such protests generally must show that the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling, although a pipeline is not required to reduce its rate below the level grandfathered under the EP Act. Under Order No. 561, a pipeline must as a general rule utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances.

In 2015, the tariff rate for our Ozark system was reset on a cost-of-service basis and is subject to the FERC indexing rules. The tariff rates for our Lakehead, North Dakota and Bakken systems are set using a combination of the FERC indexing rules (which apply to the base rates on those systems), FERC-approved surcharges for particular projects that were approved under the FERC’s settlement rules and, in the case of the North Dakota and Bakken systems, contractual agreements.

The inflation index applied to those rates subject to the FERC indexing rules is determined by a formula that is established by FERC and is subject to review every five years. On December 16, 2010, the FERC set the index for the period from July 2011 through June 2016 at the Producer Price Index for Finished Goods, or PPI-FG, plus 2.65 percentage points. Based on this formula, the index resulted in an increase of approximately 3.9%, 4.6%, and (2.0)% for 2014, 2015 and 2016, respectively. On December 18, 2015, the FERC set the index for the period from July 2016 through June 2021 at PPI-FG plus 1.23 percentage points.

On October 20, 2016, the FERC issued an Advanced Notice of Proposed Rulemaking (ANOPR) seeking comments on proposed changes to its review of oil pipeline index rate filings and reporting requirements. Specifically, the Commission proposes to reject increases to indexed rates and indexed rate ceilings if certain criteria are met. Such rate increase rejections would be outright and would not be prompted by a shipper protest (as is the case currently) or involve a hearing into the merits of the rate increase. An ANOPR is an initial step taken by a regulatory agency to obtain comments from impacted parties. Before issuing a final rule regarding these issues the FERC must also undertake a Notice of Proposed Rulemaking (NOPR) process. As a result, it is unlikely that this issue will be resolved in 2017.

FERC Allowance for Income Taxes in Interstate Common Carrier Pipeline Rates

Under current FERC policy, pipelines regulated by FERC that are owned by entities organized as Master Limited Partnerships, or MLPs, may include an income tax allowance in their cost-of-service rates to the extent the income generated from regulated activities was subject to an actual or potential income tax liability. Pursuant to this policy, a FERC-regulated pipeline that is a tax pass-through entity seeking such an income tax allowance must establish that its owners, partners or members have an actual or potential income tax obligation on the company’s income from regulated activities. Whether a particular pipeline’s owners have an actual or potential income tax liability is reviewed by the FERC on a case-by-case basis. To the extent any of our FERC-regulated oil pipeline systems were to file cost-of-service rates, their entitlement to an income tax allowance would be assessed under the FERC policy statement and the facts existing at the relevant time.

The current FERC income tax allowance policy has recently been drawn into question by a decision of the United States Court of Appeals (D.C. Circuit). In its July 1, 2016 decision in the United Airlines case the court found that the FERC had failed to demonstrate that its income tax allowance policy — in conjunction with its rate of return methodology — does not result in double recovery of taxes for partnerships and asked the FERC to establish an income tax recovery mechanism for which it can demonstrate that there is no double recovery. It is unclear at this point whether the current FERC income tax recovery mechanism will be upheld or whether the FERC will need to change its income tax recovery mechanism and if so what the new mechanism might look like. It is not expected that this issue will be fully resolved in 2017.

FERC Return on Equity Policy for Oil Pipelines

The FERC Return on Equity, or ROE, for oil pipelines is determined using a “two-step” discounted cash flow methodology. This methodology accounts for a long-term growth estimate in addition to a short-term growth rate estimate. For purposes of calculating the long-term growth rate, the FERC has traditionally used projected Gross Domestic Product, or GDP, growth as a proxy for the long-term growth rate. The current FERC policy for calculating ROE was set out in the FERC’s Policy Statement regarding Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity. According to the Policy Statement, MLPs are included in the

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ROE proxy group for oil pipelines, and there is no ceiling on the level of distributions included in the FERC’s discounted cash flow methodology. The Policy Statement further indicates that the Institutional Brokers’ Estimate System, or IBES, forecasts should remain the basis for the short-term growth forecast used in the discounted cash flow calculation and the respective two-thirds and one-third weightings of the short and long-term growth factors should be used. The Policy Statement also indicates that the GDP forecast used for the long-term growth rate should be reduced by 50% for all MLPs included in the proxy group. The actual ROEs to be calculated under the Policy Statement are dependent on the companies included in the proxy group and the specific conditions existing at the time the ROE is calculated in each case. The FERC’s ROE policy for MLPs is also potentially impacted by the United Airlines decision discussed above.

Accounting for Pipeline Assessment Costs

The FERC’s policies describe how FERC-regulated companies should account for costs associated with implementing the pipeline integrity management requirements of the United States Department of Transportation, or DOT, and the Pipeline and Hazardous Materials Safety Administration, or PHMSA. FERC-regulated companies are generally required to recognize costs incurred for performing pipeline assessments that are part of a pipeline integrity management program as a maintenance expense in the period in which the costs are incurred. Costs for items such as rehabilitation projects designed to extend the useful life of the system can continue to be capitalized to the extent permitted under the existing rules. Consistent with the FERC’s policies, we expense all internal inspection costs for all our pipeline systems, whether or not they are subject to the FERC’s regulation. Refer to Part II. Item 8. Financial Statements and Supplementary Data, Note 2. Summary of Significant Accounting Policies included in our consolidated financial statements of this annual report on Form 10-K for additional discussion.

Regulation of Intrastate Natural Gas Pipelines

Our operations in Texas are subject to regulation under the Texas Utilities Code and the Texas Natural Resources Code, as implemented by the Texas Railroad Commission, or TRRC. Generally, the TRRC is vested with authority to ensure that rates charged for natural gas sales and transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law, unless challenged in a complaint. We cannot predict whether such a complaint may be filed against us or whether the TRRC will change its method of regulating rates. Pursuant to authority granted to it by the Texas Natural Resources Code, the TRRC has adopted by rule an Informal Complaint Process that applies to rate issues associated with gathering or transmission systems, thus subjecting gathering and intrastate pipeline activities of Enbridge to the jurisdiction of the TRRC.

In Oklahoma, intrastate natural gas pipelines and gathering systems are subject to regulation by the Oklahoma, Corporation Commission, or OCC. Specifically, the OCC is vested with the authority to prescribe and enforce maximum rates for the transportation and transmission of natural gas. These rates may be amended or altered at any time by the OCC. However, a company affected by a rate change will be given at least ten days’ notice in order to introduce evidence of opposition to such amendment. Adjustment of claims or settlement of controversies regarding rates between transportation and transmission companies and customers will be mediated by the OCC prior to any hearing on the dispute, upon request. An entity operating an intrastate natural gas pipeline or gathering system in Oklahoma is subject to the jurisdiction of the OCC, and failure to comply with an OCC order regarding rate requirements could result in contempt proceedings instituted before the OCC by any affected party.

Regulation by the FERC of Intrastate Natural Gas Pipelines

Our Texas and Oklahoma intrastate pipelines are generally not subject to regulation by the FERC. However, to the extent our intrastate pipelines transport natural gas in interstate commerce, the rates, terms and conditions of such transportation are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act of 1978, or NGPA. In addition, under FERC regulations we are subject to market manipulation and transparency rules. This includes the annual reporting requirements pursuant to FERC Order No. 735 et al. Failure to comply with FERC rules, regulations and orders can result in the imposition of administrative, civil and criminal penalties.

Natural Gas Gathering Regulation

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from the jurisdiction of the FERC. We own certain natural gas facilities that we believe meet the traditional tests the FERC has used to establish a facility’s status as a gatherer not subject to FERC jurisdiction. However, to the extent our gathering systems buy and sell natural gas that is processed or that can be sold into the market without being processed, such gatherers, in their capacity as buyers and sellers of natural gas, are subject to certain reporting requirements resulting from the FERC Order 704 series.

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State regulations of gathering facilities typically address the safety and environmental concerns involved in the design, construction, installation, testing and operation of gathering facilities. In addition, in some circumstances, nondiscriminatory requirements are also addressed; however, state regulators have not historically taken an active role in setting or reviewing rates for gathering facilities absent a shipper protest. Many of the producing states have previously adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access or perceived rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to significant and unduly burdensome state or federal regulation of rates and services.

NGL Pipeline Regulation

The mainline and gathering portions of the Texas Express NGL system are common carriers subject to regulation by various federal agencies and/or the TRRC. The FERC regulates the interstate pipeline transportation of crude oil, petroleum products, and other liquids such as NGLs, collectively called “petroleum pipelines.” The FERC regulates these operations pursuant to the Interstate Commerce Act, or ICA, and the Energy Policy Act of 1992, or EP Act of 1992. The ICA and its implementing regulations require that tariff rates for interstate service on petroleum pipelines be just and reasonable and must not be unduly discriminatory or confer undue preference on any shipper.

The EP Act of 1992 required the FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, the FERC adopted an indexed rate methodology. If the rate levels on Texas Express NGL system were subject to formal review or challenge before the FERC, the Texas Express NGL system would be required to produce a traditional cost of service review justifying its revenues or demonstrate it lacks significant market power.

Two of our other NGL lines, which do not provide service to third parties, operate under FERC-granted waivers from the reporting requirements of Sections 6 and 20 of the ICA. These waivers are effective until a third party shipper requests service. In addition, certain of our NGL lines are subject to regulation as a common carrier by the TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates we charge for NGL transportation service are deemed just and reasonable under Texas law unless challenged by a complaint. Complaints to state agencies have been infrequent and are usually informally resolved, but ongoing industry practice might indicate an increase in complaints and TRRC oversight. Although we cannot assure that our intrastate rates would ultimately be upheld if challenged, we believe that, given this history, the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.

Sales of Natural Gas, Crude Oil, Condensate and Natural Gas Liquids

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

Our sales of crude oil, 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. Regulations implemented by the FERC could increase the cost of transportation service on certain petroleum products pipelines, however, we do not believe that these regulations will affect us any differently than other marketers of these products transporting on ICA-regulated pipelines.

Other Regulation

The governments of the United States and Canada have, by treaty, agreed to reduce barriers to foreign trade and stimulate the flow of goods and services between the United States and Canada, which includes the passage of oil and natural gas through the pipelines of one country across the territory of the other. Individual international border crossing points require United States government permits that may be terminated or amended at the

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discretion of the United States Government. These permits provide that pipelines may be inspected by or subject to orders issued by federal and, on occasion, state government agencies.

FERC Tariffs and Transportation

Lakehead system

Under the published rate tariff as of December 31, 2016 for transportation on the Lakehead system, the rates for transportation of light, medium and heavy crude oil from the Canada-United States international border near Neche, North Dakota and from Clearbrook, Minnesota to principal delivery points are set forth below:

		Published Transportation Rate Per Barrel(1)
		Light				Medium				Heavy
From the international border near Neche, North Dakota:
To Clearbrook, Minnesota		$	0.4608			$	0.4884			$	0.5370
To Superior, Wisconsin		$	0.9712			$	1.0377			$	1.1540
To Chicago, Illinois area		$	2.1393			$	2.3011			$	2.5849
To Marysville, Michigan area		$	2.5778			$	2.7746			$	3.1201
To Buffalo, New York area		$	2.6415			$	2.8437			$	3.1974
Clearbrook, Minnesota to Chicago		$	1.8906			$	2.0248			$	2.2601

The transportation rates as of December 31, 2016 for medium and heavy crude oil are higher than the transportation rates for light crude oil set forth in this table to compensate for differences in the costs of shipping different types and grades of liquid hydrocarbons. The Lakehead system periodically adjusts transportation rates as allowed under the FERC’s index methodology and the tariff agreements described below.

Base Rates

The Lakehead system’s base rates are subject to an annual adjustment, which cannot exceed established ceiling rates as approved by the FERC and are determined in compliance with the FERC approved index methodology. On May 31, 2016, Enbridge filed FERC tariff No. 43.21.0 that decreased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 0.979865 issued by the FERC on May 19, 2016 in Docket No. RM93-11-000.

Facilities Surcharge Mechanism

In June 2004, the FERC approved an Offer of Settlement in Docket No. OR04-2-000 between Lakehead and CAPP, which implemented a Facilities Surcharge Mechanism, or FSM, to be calculated separately from and incrementally to the then-existing surcharges in its tariff rates. The FSM includes additional projects negotiated and agreed upon between Lakehead and CAPP as a transparent, cost-of-service based tariff mechanism. This allows the Lakehead system to recover the costs associated with particular shipper-requested projects through an incremental surcharge layered on top of the existing base rates. The FSM Settlement requires the Lakehead system to adjust the FSM annually to reflect the latest estimates for the upcoming year and to adjust for the difference between estimates and actual cost and throughput from the prior year.

The FERC approved the FSM to take effect as of July 1, 2004, and the FSM was expressly designed to be open-ended. In its approval of the FSM Settlement, the FERC accepted the Lakehead system’s proposal “to submit for FERC review and approval future agreements resulting from negotiations with CAPP where the parties have agreed that recovery of costs through the FSM is desirable and appropriate.” At the time it was initially established, four projects were included in the FSM. Over the course of several years, the FERC subsequently approved the addition of new projects to the FSM, and as of December 31, 2016, 25 projects are included in the FSM.

On August 14, 2008, the FERC approved an Amendment to the FSM Settlement to allow the Lakehead system to include in the FSM particular shipper-requested projects that are not yet in service as of April 1 of each year, provided there is an annual adjustment for differences between actual and estimated throughput and costs.

On December 15, 2015, Enbridge filed a Supplement to the Settlement in Docket No. OR16-9-000 seeking approval for the recovery of a negotiated amount for the costs associated with the “Interim Lakehead Operational Tank Service” project. This project permits the recovery of a negotiated cost of $1.5 million per month for the

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provision of tank service. The FERC accepted the Supplement on February 1, 2016 to permit the recovery of the negotiated cost of $1.5 million per month for the provision of tank service. On February 29, 2016, Enbridge filed FERC tariff 43.20.0 which included the costs related to the monthly negotiated fee for the “Interim Lakehead Operational Tank Services” project.

On December 14, 2016, Enbridge filed a Supplement to the Settlement in Docket No. OR17-3-000 seeking approval to recover $30 million of early development costs related to the Line 61 Twin Project.

As of December 31, 2016, the FSM was $1.1899 per barrel for light crude oil movements from the Canada-United States international border near Neche, North Dakota to Chicago, Illinois.

International Joint Tariff

FERC Tariff No. 45.11.0, issued May 31, 2016, revised the International Joint Tariff, or IJT, effective July 1, 2016, by decreasing the transportation tolls by 0.46%. The IJT provides rates applicable to the transportation of petroleum from all receipt points in Western Canada on the Enbridge Pipelines Inc., or Enbridge Pipelines, Canadian Mainline system to all delivery points on the Lakehead Pipeline system owned by Enbridge Energy, Limited Partnership, or OLP, and to delivery points on the Canadian Mainline located downstream of the Lakehead system. In summary, the IJT provides a simplified tolling structure to cover transportation services that cross the international border and provides a rate that is equal to or less than the sum of the combined Canadian Mainline and Lakehead system rates on file and in effect.

FERC Tariff No. 45.12.0, issued July 22, 2016, revised the IJT, effective September 1, 2016, by adjusting certain expansion surcharges for negative inflation.

Mid-Continent system

The Ozark system is located in the Mid-Continent region of the United States. Specifically, the system originates in Cushing, Oklahoma, and offers transportation service to Wood River, Illinois.

Effective July 1, 2016, FERC Tariff No. 48.7.0 did not affect the transportation rate because the cost of service application Enbridge Ozark filed in 2015 used a test period that fell within the calendar year on which the 2016 index was based. Accordingly, the rate was not eligible for the index adjustment. The viscosity surcharge on that tariff decreased in compliance with the indexed rate ceilings allowed by the FERC, which incorporated the multiplier of 0.979865 issued by the FERC on May 19, 2016 in Docket No. RM93-11-000. However due to rounding, the viscosity surcharge remained unchanged on the tariff.

On December 15, 2016, Enbridge Ozark launched a public open season to offer approximately 115,000 barrels per day of expansion capacity on its system from Cushing, Oklahoma to Wood River, Illinois for committed volumes of crude petroleum that would not be subject to prorationing. The open season provided an opportunity for potential shippers to support the expansion by making minimum volume commitments for a ten-year term. The open season closed on January 19, 2017. In December 2016, we entered into an agreement to sell the Ozark pipeline system to a subsidiary of MPLX LP. For further details, see Item 1. Financial Statements, Note 11. Property, Plant and Equipment.

The transportation rate for light crude oil on the Ozark system is set forth below:

		Published Transportation Rate Per Barrel(1)(2)
From Cushing, Oklahoma to Wood River, Illinois		$	0.8403

North Dakota system

The North Dakota Pipeline system consists of both gathering and trunkline assets. North Dakota Pipeline rates consist of a base rate that is subject to the annual FERC index, and two cost of service surcharges, the Phase 5 Looping and the Phase 6 surcharges, which are applicable to specific receipt and delivery points. In addition, the North Dakota Pipeline system includes both committed and uncommitted rates for service on the Bakken Project for deliveries to Berthold, North Dakota.

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Phase 5 Looping and Phase 6 Expansion Surcharges

Effective January 1, 2008, the looping surcharge was implemented as a part of the North Dakota Phase 5 expansion program, referred to as North Dakota Phase 5. The Phase 5 Offer of Settlement that was filed with the FERC for an expansion of the system was approved by the Commission on October 31, 2006 in Docket No. OR06-9-000. The Phase 5 Offer of Settlement outlined the looping surcharge as a cost-of-service based surcharge that is adjusted each year for differences between estimated and actual costs and throughput and is not subject to the FERC indexing methodology. This surcharge was initially applicable for five years immediately following the in-service date of North Dakota Phase 5, which was January 2008. The looping surcharge was applied to volumes originating at Trenton, Little Muddy or Alexander, North Dakota. Effective April 1, 2010, the term of the looping surcharge on the North Dakota system was extended by four years, and ended on December 31, 2016. The impact of the term extension reduced the looping surcharge substantially thereby moderating the rate impact on shippers.

The FERC approved the Phase 6 expansion Offer of Settlement submitted by Enbridge North Dakota on October 20, 2008, in Docket No. OR08-6-000. Under the terms of the settlement, expansion costs are recovered through a cost-of-service based surcharge on all shipments to Clearbrook, Minnesota. The surcharge was in addition to existing base rates and the Phase 5 surcharges and was adjusted on an annual basis to actual costs and throughput. It was not subject to the FERC index methodology. The Phase 6 surcharge became effective on January 1, 2010 and expired on December 31, 2016.

Phase 5 Looping and Phase 6 Surcharge Rate Adjustments

Effective April 1, 2016, FERC Tariff No. 3.18.0 updated the calculation of the Phase 5 Looping and Phase 6 surcharges. These cost-of-service based surcharges are adjusted each year to actual costs and throughput and are not subject to the FERC indexing methodology. The Phase 5 Looping surcharge increased by approximately $0.05 per barrel to $0.24 per barrel, primarily due to a decrease in forecasted throughput. The Phase 6 surcharge decreased by approximately $0.08 per barrel to $0.31 per barrel, primarily due to return of prior period over-recoveries to shippers.

FERC Tariff No. 3.22.0 was filed to reflect the December 31, 2016 expiration of the Phase 5 Looping surcharge and the Phase 6 surcharge, effective, January 1, 2017. Additionally, this tariff discounted four existing base system rates to Tioga, North Dakota.

The Bakken Loop Project

On August 26, 2010, the North Dakota system and Enbridge Pipelines (Bakken) L.P. filed a Petition for Declaratory Order seeking the approval of priority service for the North Dakota portion of the Bakken Loop Project as well as the overall tariff and rate structure for the United States portions of the program. The Petition for Declaratory Order was approved by the FERC on November 22, 2010 in Docket No. OR10-19-000, and the Bakken Loop Project went into service on March 1, 2013. The uncommitted trunkline rates to Berthold, North Dakota consist of a base rate whereas the committed trunkline rates consist of both a base committed rate and a flow-through operating cost charge component.

The Bakken Loop Project Rate Adjustments

Effective July 1, 2016, in accordance with the Bakken Project Transportation Services Agreement, or TSA, FERC Tariff No. 3.20.0 adjusted the operating cost charge component of the committed trunkline rates to Berthold, North Dakota to the actual operating costs and throughput for 2015 and the forecasted operating costs and throughput for 2016. The operating cost charge decreased by $0.32 from $0.38 to $0.06.

Base System Rate Adjustments

Effective March 1, 2016 FERC Tariff No. 2.6.0 established a Storage in Transit service at Minot, North Dakota which permits shippers to park crude petroleum and re-enter crude petroleum at a later date for transportation to Clearbrook, Minnesota. Nominations to the Minot Storage in Transit Site are subject to the applicable tariff rate from the initial receipt point to Clearbrook, Minnesota.

Effective July 1, 2016, FERC Tariff No. 3.19.0 established new delivery points at Grenora, North Dakota to Grenora, Merchant Storage, North Dakota and Little Muddy, North Dakota to Little Muddy, Merchant Storage, North Dakota.

Effective July 1, 2016, FERC Tariff No. 3.20.0 decreased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 0.979865 issued by the FERC on May 19, 2016 in

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Docket No. RM93-11-000. In addition, this tariff discounted the terminal charge for gathering or truck unloading at Little Muddy, North Dakota from the established 2016 ceiling rate of $0.22 to $0.01 per barrel.

Effective December 1, 2016 FERC Tariff No. 3.21.0 was filed to cancel trunkline transportation rates from Reserve, Montana to Clearbrook, Minnesota, Grenora, Merchant Storage, North Dakota, Tioga, North Dakota and Stanley, North Dakota, to reflect that the pipeline is no longer providing service from this receipt point.

The rates and surcharges for transportation of light crude oil on the North Dakota system are set forth below:

		Published Transportation Rate Per Barrel(1)
From Minot, Berthold and Stanley, North Dakota to Clearbrook, Minnesota		$	1.4246
From Grenora, North Dakota to Clearbrook, Minnesota		$	1.5864
From Tioga, North Dakota to Clearbrook, Minnesota		$	1.4601
From Trenton, North Dakota to Clearbrook, Minnesota		$	2.0108
From Alexander, North Dakota to Clearbrook, Minnesota		$	2.0643
From Little Muddy, North Dakota to Clearbrook, Minnesota		$	2.0108
From Grenora, North Dakota to Grenora, Merchant Storage, North Dakota (pump over)		$	0.2785
From Little Muddy, North Dakota to Little Muddy, Merchant Storage, North Dakota (pump over)		$	0.2785
From Grenora, North Dakota to Tioga, North Dakota		$	0.5513
From Trenton, North Dakota to Tioga, North Dakota		$	0.9095
From Alexander, North Dakota to Tioga, North Dakota		$	0.9629
From Little Muddy, North Dakota to Tioga, North Dakota		$	0.9095
From Stanley, North Dakota to Stanley, North Dakota (pump-over)		$	0.2785
From Tioga, North Dakota to Stanley, North Dakota		$	0.8559
From Grenora, North Dakota to Stanley, North Dakota		$	1.1642
From Trenton, North Dakota to Stanley, North Dakota		$	1.5742
From Alexander, North Dakota to Stanley, North Dakota		$	1.6236
From Little Muddy, North Dakota to Stanley, North Dakota		$	1.5742
From Berthold, North Dakota to Berthold, North Dakota (pump-over)		$	0.2646
From Stanley, North Dakota to Berthold, North Dakota		$	0.8559
From Tioga, North Dakota to Berthold, North Dakota		$	0.8559

Bakken Pipeline

The Bakken Pipeline extends from Berthold, North Dakota to the international border near Portal, North Dakota. Tariff rates on the Bakken Pipeline consist of a local tariff with a local uncommitted rate for service to the international border, and an international joint tariff with both committed and uncommitted joint rates for service to Cromer, Manitoba.

As previously mentioned, the North Dakota system and Enbridge Pipelines (Bakken) L.P. filed a Petition for Declaratory Order seeking approval to provide priority service for the North Dakota portion of the Bakken pipeline as well as the overall tariff and rate structure for the U.S. portions of the Bakken pipeline. The Petition for Declaratory Order was approved by the FERC on November 22, 2010 in Docket No. OR10-19-000, and the Bakken pipeline went into service on March 1, 2013.

Local Tariff

Effective July 1, 2016, FERC Tariff No. 2.3.0 decreased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 0.979865 issued by the FERC on May 19, 2016, in Docket No. RM93-11-000.

The local uncommitted rate for transportation of light crude oil on the Bakken system is set forth below:

		Published Transportation Rate Per Barrel(1)
From Berthold, North Dakota to the international border near Portal, North Dakota		$	1.2728

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International Joint Tariff

Effective July 1, 2016, the Bakken system filed FERC Tariff No. 3.5.0. This filing was a compliance filing in accordance with transportation service agreements included in the Petition for Declaratory Order filed on August 26, 2010 in Docket No. OR10-19-000. This tariff included an adjustment for the operating cost charge, which is part of the committed rate structure. The committed rate structure consists of two components — a base committed rate and an operating cost charge. The operating cost charge is a flow-through of the related operating costs, and is based on throughput. The operating cost charge for Bakken as of July 1, 2016, increased by $0.65 from a credit of $0.12 to a charge of $0.53.

The uncommitted joint rate for transportation of light crude oil on the Bakken system is set forth below:

		Published Transportation Rate Per Barrel(1)
From Berthold, North Dakota to Cromer, Manitoba		$	2.0990

The committed joint rates for transportation of light crude oil on the Bakken system is set forth below:

		Published Transportation Rate Per Barrel(1)
From Berthold, North Dakota to Cromer, Manitoba (5 Year Commitment)		$	2.0115
From Berthold, North Dakota to Cromer, Manitoba (10 Year Commitment) (<40,000 bpd)		$	1.6708
From Berthold, North Dakota to Cromer, Manitoba (5 Year Commitment) (>40,000 bpd)		$	1.4569

Safety Regulation and Environmental

General

Our transmission and gathering pipelines, storage and processing facilities and railcar operations are subject to extensive environmental, operational and safety regulation at the federal and state level. 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.

Pipeline Safety and Transportation Regulation

Our transmission and gathering pipelines are subject to regulation by the Department of Transportation, or DOT, and the Pipeline and Hazardous Material Safety Administration, or PHMSA, under the Pipeline Safety Act, or PSA, specifically Volume 49 of the Code of Federal Regulations, Parts 192 (gas) and 195 (hazardous liquids). The regulations pertain to the design, installation, testing, construction, operation, replacement and management of transmission and gathering pipeline facilities. PHMSA is the agency charged with regulating the safe transportation of hazardous materials under all modes of transportation, including interstate and intrastate pipelines. Periodically the PSA has been reauthorized and amended, imposing new mandates on the regulator to promulgate new regulations and imposing direct mandates on operators of pipelines. The most recent reauthorization occurred in 2016.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. Congress also has mandated that PHMSA adopt regulations to implement these recommendations, along with a number of additional regulatory measures. 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.

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We have incorporated all existing requirements into our programs by the required regulatory deadlines, and are continually incorporating any 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, or NTSB, may perform an investigation of a significant accident to determine the probable cause and issue safety recommendations to prevent future accidents. Any release that results in an enforcement action or NTSB investigation, such as those associated with Line 6B near Marshall, Michigan and Line 14 near Grand Marsh, Wisconsin, could have a material impact on system throughput or compliance costs. As part of the Corrective Action Order, or CAO, related to the Grand Marsh release, we were required to develop and implement a comprehensive plan to address wide-ranging safety initiatives not only for Line 14, but for our entire Lakehead System.

We believe that our pipeline and railcar operations are in substantial compliance with applicable operational and safety requirements. In instances of non-compliance, we have taken actions to remediate the situations. 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 crude oil and other liquid hydrocarbon materials or emissions from natural gas processing, treating, or compression facilities. As with the pipeline and processing industry in general, complying with current and anticipated environmental laws and regulations increases our overall cost of doing business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position since the operations of our competitors are generally similarly affected.

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

There are also risks of accidental releases into the environment associated with our operations, such as releases or spills of crude oil, natural gas liquids, natural gas or other substances from our pipelines or 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.

Although we are entitled, in certain circumstances, to indemnification from third parties for environmental liabilities relating to assets we acquired from those parties, these contractual indemnification rights are limited, and accordingly, we may be required to bear substantial environmental expenses. However, we believe that through our due diligence process, we identify and manage substantial issues.

Air and Water Emissions.  Our operations are subject to the Clean Air Act, or CAA, and the Clean Water Act, or CWA, and comparable 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 permit approvals for any new or acquired facilities. The operations of our pipeline facilities subject to the Environmental Protection Agency’s, or EPA, Spill Prevention, Control, and Countermeasures Rule are currently in substantial compliance. Our facilities subject to existing EPA Part 98 Subpart C and W Greenhouse Gas Reporting Program, or GHGRP, rules have reported emissions prior to the annual filing deadlines.

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On October 22, 2015, the EPA finalized amendments to the GHGRP to include natural gas gathering and boosting systems, well completions, and blowdown emissions associated with transmission pipelines. The rule effective date for data collection was January 1, 2016 and reporting begins for calendar year 2017 for applicable facilities.

On October 31, 2016, the EPA finalized rule revisions in the Code of Federal Regulations, or CFR, relating to test methods and performance specifications impacting facilities with stationary spark ignition internal combustion engines.

In addition, on September 18, 2015, the EPA published a proposed rule, Subpart OOOOa, which would update the original 2012 standards to include additional reductions in methane and VOCs in the oil and gas industry. On June 3, 2016, EPA published NSPS OOOOa in the Federal Register which includes seven areas of applicability for previously unaffected sources. On July 15, 2016 fifteen states filed suit in the District of Columbia Circuit Court objecting the rule. The current compliance deadline for OOOOa is June 2017.

On October 22, 2015, the EPA responded to a petition made by the Environmental Integrity Project to include the oil and gas extraction industrial sector in the scope of covered sectors of Section 313 of the Emergency Planning and Community Right-to-Know Act, commonly known as the Toxic Release Inventory, or TRI. On January 6, 2017, EPA proposed a rule to add all natural gas processing facilities meeting applicability thresholds as a covered sector. As part of the proposal, EPA declined to extend TRI reporting requirements to the oil and gas extraction activities.

The EPA has issued the Oil and Gas Information Request, or ICR, scoped to the oil and gas industry. MEP received notification of ICR on November 22, 2016 in which EPA will ask the oil and gas industry members to provide extensive information for EPA to develop regulations to further reduce methane and VOC emissions. EPA responses are due 180 days from receipt of the mailed ICR document.

On June 29, 2015, the EPA published the Clean Water Rule: Definition of “Waters of the United States.” The new rule is intended to clarify what is considered Waters of the United States, or WOTUS, with respect to discharges of pollutants, including fill material during construction and maintenance operations, to the covered water. This regulation is the subject of an ongoing legal challenge and has the potential to increase our operating and capital costs to construct, maintain and upgrade equipment and facilities. The Oil Pollution Act, or OPA, was enacted in 1990 and amends parts of the CWA and other statutes as they pertain to the prevention of and response to oil spills. Under the OPA, we could be subject to strict, joint and potentially unlimited liability for removal costs and other consequences of an oil spill from our facilities into navigable waters, along shorelines or in an exclusive economic zone of the United States. The OPA also imposes certain spill prevention, control and countermeasure requirements for many of our non-pipeline facilities, such as the preparation of detailed oil spill emergency response plans and the construction of dikes or other containment structures to prevent contamination of navigable or other waters in the event of an oil overflow, rupture or release. For our liquid pipeline facilities, the OPA imposes requirements for emergency plans to be prepared, submitted and approved by the DOT. For our non-transportation facilities, such as storage tanks that are not integral to our pipeline transportation system, the OPA regulations are promulgated by the EPA. We believe that we are in material compliance with these laws and regulations.

For all proposed rules, we will continue to track the progress through involvement in industry groups and will comply with regulatory requirements. We do not expect a material effect on our financial statements as a result of compliance efforts.

Hazardous Substances and Waste Management.  The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA (also known as the “Superfund” law), and similar state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons, including the owners or operators of waste disposal sites and companies that disposed or arranged for disposal of hazardous substances found at such sites. We may generate some wastes that fall within the definition of a “hazardous substance.” We may, therefore, be jointly and severally liable under CERCLA for all or part of any costs required to clean up and restore sites at which such wastes have been disposed. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Analogous state laws may apply to a broader range of substances than CERCLA and, in some instances, may offer fewer exemptions from liability. We have not received any notification that we may be potentially responsible for material cleanup costs under CERCLA or similar state laws.

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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, the Resource Conservation & Recovery Act and analogous state laws as described above.

Under these laws, we could incur substantial expense to remediate such contamination, including contamination caused by prior owners and operators. In addition, Enbridge Management, as the entity with managerial responsibility for us, could also be liable for such costs to the extent that we are unable to fulfill our obligations. We have conducted site investigations at some of our facilities to assess historical environmental issues, and we are currently addressing soil and groundwater contamination at various facilities through remediation and monitoring programs, with oversight by the applicable governmental agencies where appropriate.

EMPLOYEES

Neither we nor Enbridge Management have any employees. Our General Partner has delegated to Enbridge Management, pursuant to a delegation of control agreement, substantially all of the responsibility for our day-to-day management and operation. Our General Partner, however, retains certain functions and approval rights over our operations. To fulfill its management obligations, Enbridge Management has entered into agreements with Enbridge and several of its affiliates to provide Enbridge Management with the necessary services and support personnel who act on Enbridge Management’s behalf as its agents. We are ultimately responsible for reimbursing these service providers based on the costs that they incur in performing these services.

INSURANCE

Our operations are subject to many hazards inherent in the liquid petroleum and natural gas gathering, treating, processing and transportation 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 maintain commercial liability insurance coverage that is consistent with coverage considered customary for our industry. We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries through the policy renewal date of May 1, 2017. The insurance coverage also includes property insurance coverage on our assets that includes earnings interruption resulting from an insurable event, except for pipeline assets that are not located at water crossings. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement we have entered into with Enbridge and other Enbridge subsidiaries.

The insurance policy coverage limits and deductible amounts at December 31, 2016 for Enbridge, Inc. and its subsidiaries are:

Insurance Type		Coverage Limits				Deductible Amount
		(in millions)
Property and business interruption			Up to $650.0			$	10.0
General liability			Up to $900.0			$	0.1
Pollution liability (as included under General Liability)			Up to $900.0			$	30.0

We can make no assurance that the insurance coverage we maintain will be available or adequate for any particular risk or loss or that we will be able to maintain adequate insurance in the future at rates we consider reasonable. Although we believe that our assets are adequately covered by insurance, a substantial uninsured loss could have a material adverse effect on our financial position, results of operations and cash flows.

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TAXATION

We are not a taxable entity for U.S. federal income tax purposes. Generally, U.S. federal and state income taxes on our taxable income are borne by our individual partners through the allocation of our taxable income. In a limited number of states, an income tax is imposed upon us and generally, not our individual partners. The income tax that we bear is reflected in our consolidated financial statements. The allocation of taxable income to our individual partners may vary substantially from net income reported in our consolidated statements of income.

AVAILABLE INFORMATION

We make available free of charge on or through our Internet website http://www.enbridgepartners.com our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements, and if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934, as amended, or Exchange Act, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not part of this report.

Item 1A. Risk Factors

We encourage you to consider carefully the risk factors described below, in addition to the other information contained in or incorporated by reference into this Annual Report on Form 10-K.

RISKS RELATED TO OUR BUSINESS

We may not have sufficient cash flows to enable us to continue to pay distributions at the current level.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions at the current level. As part of our ongoing strategic review, we have announced that, among other things, we are considering the sustainability of our current level of distributions. Our current distribution level was established at a time when a significant portion of the distribution was supported by cash flow from the natural gas business, which has been adversely affected by a continued cyclical downturn.

The amount of cash we are able to distribute depends on the amount of cash we generate from our operations, which can fluctuate quarterly based upon a number of factors, including:

In addition, the amount of cash we distribute depends primarily on our cash flow rather than net income or net loss. Therefore, we may make cash distributions for periods in which we record net losses or may make no distributions for periods in which we record net income. Other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to declare quarterly cash distributions, 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.

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Our actual 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 maintain or increase cash distributions.

Our strategy 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, permitting at federal, state and local levels, as well as 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 currently 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:

Any or all of these methods may not be available when needed or may adversely affect our future results of operations and cash flows.

Our revenues and cash flows may not increase immediately on 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. In addition, circumstances may occur from time to time, such as the inability to obtain a necessary permit, which could cause us to cancel a project. If our revenues and cash flow do not increase at projected levels because of substantial unanticipated delays, project cancellations 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 ability to access capital markets and credit on attractive terms to obtain funding for our capital projects and acquisitions may be limited.

Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Domestic and international economic conditions affect the functioning of capital markets and the availability of credit. Adverse economic conditions, such as the recent decline and currently depressed levels of commodity prices, have resulted in weakness and volatility in the capital markets, which 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.

A downgrade in our credit rating could require us to provide collateral for our hedging liabilities and negatively impact our interest costs and borrowing capacity under our Credit Facilities.

Standard & Poor’s, or S&P, Dominion Bond Rating System, or DBRS, and Moody’s Investors Service, or Moody’s, rate our non-credit enhanced, senior unsecured debt. Although we are not aware of current plans by the ratings agencies to lower their respective ratings on such debt, we cannot be assured that such credit ratings will not be downgraded.

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Currently, we are parties 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 us to provide assurances of performance if our counterparties’ exposure to us exceeds certain levels or thresholds. We generally provide letters of credit to satisfy such requirements. At December 31, 2016, we have provided $119.5 million in the form of letters of credit as assurances of performance for our then outstanding derivative financial instruments. In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by S&P and Moody’s, we would be required to provide letters of credit in substantially greater amounts to satisfy the requirements of our ISDA® agreements. For example, if our credit ratings had been at the lowest level of investment grade at December 31, 2016, we would have been required to provide additional letters of credit in the aggregate amount of $60.1 million. The amounts of any letters of credit we would have to establish under the terms of our ISDA® agreements would reduce the amount that we are able to borrow under our senior unsecured revolving credit facility and our 364-day credit facility, referred to as our Credit Facilities.

Our acquisition strategy may be unsuccessful if we incorrectly predict operating results, are unable to identify and complete future acquisitions and integrate acquired assets or businesses.

The acquisition of complementary energy delivery assets is a component of our strategy. Acquisitions present various risks and challenges, including:

In addition, we may be unable to identify acquisition targets or consummate acquisitions in the future.

Our financial performance could be adversely affected if our pipeline systems are used less.

Our financial performance depends to a large extent on the volumes transported on our liquids or natural gas pipeline systems. Decreases in the volumes transported by our systems can directly and adversely affect our revenues and results of operations. The volume transported on our pipelines can be influenced by factors beyond our control including:

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As an example, the volume of shipments on our Lakehead system depends heavily on the supplies of western Canadian crude oil. Insufficient supplies of western Canadian crude oil will adversely affect our business by limiting shipments on our Lakehead system. For example, extreme wildfires in northeastern Alberta impacted volumes on our Lakehead system during the second quarter of 2016. Decreases in conventional crude oil exploration and production activities in western Canada and other factors, including supply disruption, higher development costs and competition, can slow the rate of growth of our Lakehead system. The volume of crude oil that we transport on our Lakehead system, as well as the North Dakota and Bakken systems, also depends on the demand for crude oil in the Great Lakes and Midwest regions of the United States and the volumes of crude oil and refined products delivered by others into these regions and the province of Ontario. As well, there are supply driven risks around our North Dakota and Bakken assets, as lower commodity prices can reduce drilling and volumes on our systems.

In addition, our ability to increase deliveries to expand our Lakehead system in the future depends on increased supplies of western Canadian crude oil. We expect that growth in future supplies of western Canadian crude oil will come from oil sands projects in Alberta. Full utilization of additional capacity as a result of our Alberta Clipper and Southern Access pipelines and future expansions of our Lakehead system will largely depend on these anticipated increases in crude oil production from oil sands projects. A reduction in demand for crude oil or a decline in crude oil prices may make certain oil sands projects uneconomical since development costs for production of crude oil from oil sands are greater than development costs for production of conventional crude oil. Oil sands producers may cancel or delay plans to expand their facilities, as some oil sands producers have done in recent years, if crude oil prices are at levels that do not support expansion. Any cancellation or delay of oil sands projects could directly impact our Lakehead system with potential indirect impacts on our Mid-Continent, North Dakota and Bakken systems. Additionally, measures adopted by the government of the province of Alberta to increase its share of revenues from oil sands development coupled with a decline in crude oil prices could reduce the volume growth we have anticipated in expanding the capacity of our crude oil pipelines.

The volume of shipments on natural gas and NGL systems depends on the supply of natural gas and NGLs available for shipment from the producing regions that supply these systems. Supply available for shipment can be affected by many factors, including commodity prices, weather and drilling activity among other factors listed above. Volumes shipped on these systems are also affected by the demand for natural gas and NGLs in the markets these systems serve. Existing customers may not extend their contracts for a variety of reasons, including a decline in the availability of natural gas from our Mid-Continent, United States Gulf Coast and East Texas producing regions, or if the cost of transporting natural gas from other producing regions through other pipelines into the markets served by the natural gas systems were to render the delivered cost of natural gas on our systems uneconomical. We may be unable to find additional customers to replace the lost demand or transportation fees.

Our financial performance may be adversely affected by risks associated with the Alberta oil sands.

Our Lakehead system is highly dependent on sustained production from the Alberta oil sands. Alberta oil sands producers face a number of challenges that must be managed effectively to allow for sustained growth in the sector. Factors and risks affecting the oil sands industry include:

Adverse developments or trends in any of these factors could affect oil sands development or production levels and result in decreased demand for our products and services, and our failure to effectively anticipate, manage or respond to these risks could result in significant capital expenditures or increased operating costs or otherwise negatively affect our operating results or financial condition.

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Competition may reduce our revenues.

Our Lakehead system faces current and potentially further competition from other pipelines for transporting western Canadian crude oil, which may reduce our volumes and the associated revenues. To the extent that the rate is calculated using a cost-of-service methodology, these lower volumes will increase our transportation rates. The increase in transportation rates could result in rates that are higher than competitive conditions will otherwise permit. Our Lakehead system competes with other crude oil and refined product pipelines and other methods of delivering crude oil and refined products to the refining centers of Minneapolis-St. Paul, Chicago, Detroit, Toledo, Buffalo, and Sarnia, and the refinery market and pipeline hub located in the Patoka/Wood River area of southern Illinois. Refineries in the markets served by our Lakehead system compete with refineries in western Canada, the province of Ontario and the Rocky Mountain region of the United States for supplies of western Canadian crude oil.

Our Ozark pipeline system faces competition from a competitor pipeline that carries crude oil from Hardisty to Wood River and Patoka in southern Illinois.

Our North Dakota system faces competition from rail transportation driven by limited transportation infrastructure to key markets. Further, recently announced pipeline projects by competitors are supported by contracts and take-or-pay arrangements, which increases the competitive pressure on our North Dakota system.

We also encounter competition in our natural gas gathering, treating, and processing and transmission businesses. Third party new interstate natural gas transmission pipelines could reduce the revenue we derive from the intrastate transmission of natural gas. 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 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.

Our marketing operations involve market and regulatory risks.

As part of our natural gas, NGLs and condensate marketing activities, we purchase natural gas, NGLs and condensate at prices determined by prevailing market conditions. Following our purchase of natural gas, NGLs and condensate, we generally resell the natural gas, NGLs, or condensate under sales contracts that are generally comparable in terms to our purchase contracts, including any price escalation provisions. The profitability of our marketing operations may be affected by the following factors:

Our Liquids segment results may be adversely affected by commodity price volatility.

Volatility in commodity prices can impact production volumes in the oil sands region of Western Canada and the Bakken region of North Dakota, our two primary crude oil supply basins.

The relatively high costs and large up front capital investments required by oil sands projects involves significant assumptions concerning short-term and long-term crude oil fundamentals including world supply and

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demand, North American supply and demand, and price outlook among many other factors. As oil sands production is long-term in nature, the long-term outlook is significant to a producer’s investment decision. These decisions may impact the annual rate of future supply growth from the oil sands region.

While current oil sands projects are not as sensitive to short-term declines in crude oil prices, a protracted decline in crude oil prices could result in delay or cancellation of future projects. In addition, wide commodity price spreads have impacted producer netbacks and margins in the past years that largely resulted from insufficient pipeline infrastructure and takeaway capacity from producing regions in Alberta. Combined with high labor and operating costs, this has forced some producers to reconsider or defer projects until a more favorable climate for infrastructure development can be forecast.

Tight sands and shale oil production in any basin in North America such as the Bakken or the Permian will be comparatively more sensitive to the short-term changes in crude oil prices due to the sharp declining production profile associated with individual tight sands and shale oil wells. Accordingly, during periods of comparatively low prices, supply growth from the North Dakota basin may be lower, which may impact volumes on our pipeline system.

Our Natural Gas segment results have been, and may continue to be, adversely affected by commodity price volatility and risks associated with our hedging activities.

Our industry remains in a weak commodity price cycle, which could extend beyond 2017. Our exposure to commodity price volatility is inherent to our natural gas processing activities. Before hedging, approximately 30% of our gross margin attributable to our contracts in which we are paid in kind based on the price of natural gas, natural gas liquids and other petroleum based prices, which excludes unutilized transportation commitments, is expected to be attributable to contracts with some degree of commodity price exposure in 2017. MEP employs a disciplined hedging program to manage this direct commodity price risk.

We have hedged approximately 70% of our direct forecasted commodity cash flow exposure for 2017, which is lower than the over 90% that we hedged in 2016. In addition, our condensate and NGL hedge prices for 2017 are approximately 20% and on average 30% lower than 2016, respectively. Because we are not fully hedged and our hedge positions for 2017 are less favorable than they were for 2016, we will be adversely impacted by commodity price exposure on the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of our unhedged exposure and the pricing of our hedge positions, continued low prices or a substantial decline in the prices of these commodities could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make distributions.

Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure, we may be prevented from realizing the full benefits of price increases above the level of the hedges. Our hedging activities can result in substantial losses if hedging arrangements are imperfect or ineffective and our hedging policies and procedures are not followed properly or do not work as intended. Further, hedging contracts are subject to the credit risk that the other party may prove unable or unwilling to perform its obligations under the contracts, particularly during periods of weak and volatile economic conditions. In addition, certain of the financial instruments we use to hedge our commodity risk exposures must be accounted for on a mark-to-market basis. This causes periodic earnings volatility due to fluctuations in commodity prices.

We face risks associated with our ongoing strategic review

Our previously announced strategic review is ongoing and, in addition to the actions announced to date, we are considering: (i) the sustainability of our current level of distributions to unitholders, (ii) further cost efficiency measures, (iii) the potential extension of existing supportive actions by Enbridge, (iv) the sale of a portion or all of our remaining interests in the natural gas gathering and processing assets, including to Enbridge, and; (v) potential further restructuring of the general partner incentive distribution rights. Enbridge has indicated that at this time it is not planning a buy-in of us and that it expects that we will remain a publicly-traded limited partnership subsequent to the strategic review and resulting actions. The review is expected to continue into the second quarter of 2017.

There can be no assurance that any previously announced or future alternatives or initiatives that arise out of this review will be successful or deliver their anticipated benefits. We may be exposed to new and unforeseen risks and challenges, and it may be difficult to predict the success of such endeavors or the impacts to our unit holders. If we incur significant expenses or divert management, financial and other resources to a strategic alternative or

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initiative that is unsuccessful or does not meet our expectations, our results of operations and financial condition could be adversely affected. Regardless of the ultimate success of a strategic initiative, the implementation and integration could be disruptive to our current operations and plans.

Changes in, or challenges to, our rates could have a material adverse effect on our financial condition and results of operations.

The rates charged by several of our pipeline systems are regulated by the FERC or state regulatory agencies, or both. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates, the profitability of our pipeline businesses would suffer.

Under current policy, the FERC permits interstate pipelines that are subject to cost of service regulation to include an income tax allowance when calculating their regulated rates. The FERC’s income tax allowance policy has been the subject of challenge, and we cannot predict whether the FERC or a reviewing court will alter the existing policy. For example, on July 1, 2016, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision that calls into question a decade of FERC policy and precedent permitting regulated companies organized as pass-through entities for income tax purposes to include an allowance for income taxes in their rates. The court has remanded the case to the FERC to allow it to have an opportunity to provide a reasoned basis for its decision on income tax allowances for partnership pipelines. If the FERC’s policy were to change and if the FERC were to disallow a substantial portion of our pipelines’ income tax allowance, our regulated rates, and therefore our revenues and ability to make quarterly cash distributions to our unitholders, could be adversely affected.

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.

We believe that the rates we charge for transportation services on our interstate common carrier oil and open access natural gas pipelines are just and reasonable under the ICA and NGA, respectively. However, because the rates that we charge are subject to review upon an appropriately supported protest or complaint, or a regulator’s own initiative, we cannot predict what rates we will be allowed to charge in the future for service on our interstate common carrier oil and open access natural gas pipelines. Furthermore, because rates charged for transportation services must be competitive with those charged by other transporters, the rates set forth in our tariffs will be determined based on competitive factors in addition to regulatory considerations.

Increased regulation and regulatory scrutiny may reduce our revenues.

Our interstate pipelines and certain activities of our intrastate natural gas pipelines are subject to FERC regulation of terms and conditions of service. In the case of interstate natural gas pipelines, FERC also establishes requirements respecting the construction and abandonment of pipeline facilities. FERC has pending proposals to increase posting and other compliance requirements applicable to natural gas markets. Such changes could prompt an increase in FERC regulatory oversight of our pipelines and additional legislation that could increase our FERC regulatory compliance costs and decrease the net income generated by our pipeline systems.

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.

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Compliance with environmental and operational safety laws and regulations may expose us to significant costs and liabilities.

Our pipeline, gathering and processing operations are subject to federal, state and local laws and regulations relating to environmental protection and operational and worker safety. Numerous governmental authorities have the power to enforce compliance with the laws and regulations they administer and permits they issue, oftentimes imposing complex requirements and necessitating capital expenditures or increased operating costs to achieve compliance, especially when activity is in the presence of sensitive elements like water crossings, wetlands and endangered species. Our failure to comply with these laws, regulations and operating permits can result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Our operation of liquid petroleum and natural gas gathering, processing, treating and transportation facilities exposes us to the risk of incurring significant environmental and safety-related costs and liabilities. Additionally, operational modifications, including pipeline restrictions, necessary to comply with regulatory requirements and resulting from our handling of liquid petroleum and natural gas, 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. Further, environmental and operational safety laws and regulations, including but not limited to pipeline safety, wastewater discharge and air emission requirements, continue to become more stringent over time, particularly those related to the oil and gas industry. We may incur joint and several strict liability under these environmental laws and regulations in connection with discharges or releases of liquid petroleum and natural gas 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, oftentimes by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our liquid petroleum and natural gas 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.

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. In addition, the regulation of greenhouse gas emissions could result in less demand for crude oil, natural gas and NGLs over time. At the federal level, the United States Congress has in the past and may in the future consider legislation to impose a tax on carbon or require a reduction of greenhouse gas emissions. On September 22, 2009, the EPA issued a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Subsequently, on November 30, 2010, the EPA issued a supplemental rulemaking that expanded the types of industrial sources that are subject to or potentially subject to the EPA’s mandatory greenhouse gas emissions reporting requirements to include petroleum and natural gas systems. These regulations were amended by the EPA in November 2014.

The EPA concluded that the April 2010 issuance of regulations to control the greenhouse gas emissions from light duty motor vehicles (the “tailpipe rule”) automatically triggered provisions of the CAA that, in general, potentially could require stationary source facilities that emit more than 250 tons per year of carbon dioxide equivalent to obtain permits to demonstrate that best practices and technology are being used to minimize greenhouse gas emissions. On May 13, 2010, the EPA issued the “tailoring rule,” which served to establish the greenhouse gas emissions threshold for major new (and major modifications to existing) stationary sources. This rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit (Coalition for Responsible Regulation v. EPA), which dismissed the challenge on jurisdictional grounds. On appeal, the U.S. Supreme Court in 2013 (Utility Air Regulatory Group v. EPA) found the rule to be unlawful. Under the approach now being implemented by the EPA, for most purposes, new permitting provisions to control greenhouse gas emissions are required for new major source facilities that also emit 100,000 tons per year or more of carbon dioxide equivalent, or CO2e, and existing major source facilities making major modifications that also would increase greenhouse gas

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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. In August 2015, the EPA proposed regulations to reduce methane and other greenhouse gas emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025. The proposed rule would impose additional costs related to compliance with the new emission limits as well as inspections and maintenance of several types of equipment used in our operations.

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 take direct measures to further reduce greenhouse gas emissions or purchase and surrender emission allowances. 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.

Increased regulation of hydraulic fracturing and related activities could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

A significant portion of our customers’ natural gas production is developed from unconventional geological formations, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation has been proposed in Congress to both increase and decrease federal involvement in hydraulic fracturing. Legislative proposals to increase federal involvement primarily include: (i) amending the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection”; (ii) requiring federal permitting and regulatory control of hydraulic fracturing; (iii) requiring disclosure of the chemical constituents of the fluids used in the fracturing process; and (iv) requiring groundwater testing prior to hydraulic fracturing operations. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having finalized a five-year study of the potential impacts of hydraulic fracturing on drinking water resources. The EPA finalized this report in December 2016. In so doing, it described how hydraulic fracturing activities may have the potential to impact drinking water resources and the factors that could influence the frequency and severity of those impacts. Due to significant data gaps, however, the EPA was unable to estimate the national frequency of impacts or to fully characterize the severity of those impacts.

Hydraulic fracturing is also subject to an administrative proposal to increase federal regulation that may impose additional operating costs. The Bureau of Land Management has issued a new rule for hydraulic fracturing on federal and tribal lands. The rule would primarily require: (i) stricter well construction standards; (ii) the identification of “usable water”; (iii) federal preapproval for hydraulic fracturing operations; (iv) storage of hydraulic fracturing fluids in above ground tanks; and (v) public disclosure of hydraulic fracturing chemicals. The rule has been overturned and thrown out by a federal district court, but that ruling is currently the subject of an appeal to the United States Court of Appeals for the Tenth Circuit.

Future regulatory actions also have the potential to impact our operations. In August 2015, the EPA issued proposed options that would clarify the definition of “adjacent” sources of pollution in the context of the Clean Air Act permitting requirements for the oil and gas sector. This action could result in additional permitting burdens under the EPA’s Prevention of Significant Deterioration, Nonattainment New Source Review, and Title V permitting programs. The Pipeline and Hazardous Materials Safety Administration also has announced its intention to propose rules in 2016 that could, when finalized, require us to, among other things, upgrade our automatic shut-off valves at our facilities. Finally, in October 2015, the EPA proposed to reduce the National Ambient Air Quality Standard for ozone from 75 Ppb to 70 Ppb. Once final, this regulation could impose additional emissions control costs on our operations.

On April 17, 2012, the EPA adopted final rules establishing air emission controls for oil and natural gas production and natural gas processing operations. The rules addressed emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through reduced emission (or “green”) completions. The rules also established new requirements for emissions from compressors, controllers, dehydrators, storage tanks,

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gas processing plants, and certain other equipment. In August 2015, the EPA proposed regulations to reduce methane and volatile organic compound emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025. The EPA finalized these regulations on June 3, 2016 which impose additional requirements on new, modified or reconstructed natural gas gathering and production facilities and gas processing plants. In concert with these final requirements, the EPA started the formal process to collect information from the oil and gas industry that would support future rulemaking efforts to regulated greenhouse gas emissions from existing sources. We will incur additional costs related to achieve compliance with new emission limits set forth in EPA’s final regulation as well as inspections and maintenance of several types of equipment used in our operations.

Future regulatory actions also have the potential to impact our operations. The PMSHA has issued several notices of proposed rulemakings in recent years addressing a number of pipeline integrity and safety issues. The adoption of any of these requirements likely would increase our operating costs and possibly require capital expenditures. In October 2015, the EPA reduced the National Ambient Air Quality Standard for ozone from 75 Ppb to 70 Ppb. This regulation could impose additional emission control costs on our operations, although these costs are unclear as the EPA and the states have not yet completed the implementation process and the new standard is subject to an ongoing legal challenge.

These rules and proposals may require a number of modifications to our customers’ and our own operations, including, among other things, the installation of new equipment to control emissions and new integrity management requirements. Compliance with such rules could result in additional costs for us and our customers, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations. While the Trump Administration has indicated strong support for fossil fuel development, the extent to which any of the requirements or proposals are revisited in subsequent rulemaking proceedings remains uncertain.

Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. For example, on December 13, 2011, the TRRC adopted the Hydraulic Fracturing Chemical Disclosure Rule implementing a state law passed in June 2011, requiring public disclosure of hydraulic fracturing fluid contents for wells drilled under drilling permits issued after February 1, 2012. Certain states, including the State of Texas, also have taken regulatory action in response to increased seismic activity that in certain cases have been connected to hydraulic fracturing or to saltwater or drilling fluid disposal wells. In addition, at least one municipality in a state in which we operate, the City of Denton, Texas, followed others and attempted to ban hydraulic fracturing activities. This ban was overturned by the Texas Legislature. We cannot predict whether any other legislation or regulation will be enacted and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs, and prohibitions for producers who drill near our pipelines. These factors could reduce the volumes of natural gas and NGLs available to move through our gathering and other systems, which could materially adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

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

Operation of complex pipeline systems, gathering, treating and processing operations involves many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of the facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes, floods, landslides or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, any of which could also result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. Costs of pipeline seepage over time may be mitigated through insurance, however, if not discovered within the specified insurance time period we would incur full costs for the incident. In addition, we could be subject to significant fines and penalties from regulators in connection with such events. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these catastrophic events could be greater.

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United States based oil sands development opponents as well as others concerned with environmental impacts of pipeline routes advocated by our competitors have utilized political pressure to influence the timing and whether such permits are granted which could impact future pipeline development.

Our assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future. In addition, there could be service interruptions due to unknown events or conditions, or increased downtime associated with our pipelines that could have a material and adverse effect on our business and results of operations.

Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets will require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make distributions to our unitholders. As well, there could be service interruptions due to unknown events or conditions, or increased downtime associated with our pipelines that could have a material and adverse effect on our business and financial results.

Measurement adjustments on our pipeline system can be materially impacted by changes in estimation, commodity prices and other factors.

Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum pipelines. The three types of oil measurement adjustments that routinely occur on our systems include:

Quantifying oil measurement adjustments is inherently difficult because physical measurements of volumes are not practical as products continuously move through our pipelines and virtually all of our pipeline systems are located underground. In our case, measuring and quantifying oil measurement losses is especially difficult because of the length of our pipeline systems and the number of different grades of crude oil and types of crude oil products we transport. Accordingly, we utilize engineering-based models and operational assumptions to estimate product volumes in our system and associated oil measurement losses.

Natural gas measurement adjustments occur as part of the normal operating conditions associated with our natural gas 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 natural gas systems, primarily around our gathering and processing assets; (2) varying qualities of natural gas 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 natural gas systems.

We do not own a majority of the land on which our pipelines are located, which could result in increased costs and 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 or re-route portions of our pipelines 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 (including but not limited to Native American lands), and some of our agreements may grant us those rights for only a specific period of time. We are unable to predict the outcome of discussions with third parties, the governmental agencies, the appropriate Native American tribes, the tribes’ governing bodies, or the United States Bureau of Indian Affairs with respect to future arrangements or changes in applicable laws and the resulting costs, fees, bonds and taxes related to these leases, easements and rights-of-way, or grants of land rights. 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.

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

Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Cyber-attacks or security breaches could have a material adverse effect on our business, financial condition or results of operations.

Our business is dependent upon information systems and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we collect and store sensitive data in the ordinary course of our business, including personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. We conduct cyber security audits from time to time and continuously monitor our systems in an effort to mitigate the risk of cyber-attacks or security breaches; however, we do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets. Despite our security measures, our information systems may become the target of cyber-attacks or security breaches (including employee error, malfeasance or other breaches), which could compromise our network or systems and result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations.

The adoption and implementation of statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act provides additional statutory requirements for swap transactions, including energy and interest rate hedging transactions. These statutory requirements must be implemented through regulations, primarily through the Commodity Futures Trading Commission, or CFTC. To date, the Dodd-Frank Act provisions have not materially changed the way many of our swap transactions are entered into, as we have been able to continue transacting with existing counterparties in over-the-counter markets or with registered exchanges to meet hedging requirements set forth in our risk policies.

The full impact of the Dodd-Frank Act on our hedging activities as an end user is uncertain at this time, as the CFTC continues to promulgate final regulations for position limits. Although the margin rules have been finalized, the upcoming implementation of key provisions in the margin rules and the finalization of position limit provisions may create new regulatory burdens from these developments in addition to the various business conduct, recordkeeping and reporting rules resulting from the Dodd-Frank Act provisions currently in place. Moreover, longer term, fundamental changes to the swap market as a result of the Dodd-Frank Act requirements could significantly increase the cost of entering into and/or reduce the availability of new or existing swaps.

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Depending on the final rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions in circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

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 facility and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.

Our pipeline integrity program may impose significant costs and liabilities on us, while increased regulatory requirements relating to the integrity of our pipeline systems may require us to make additional capital and operating expenditures to comply with such requirements.

The Pipeline Safety Act of 2011 enacted January 3, 2012, amends the Pipeline Safety Improvement Act of 2002 in a number of significant ways, including:

In August 2012, PHMSA published rules to update pipeline safety regulations to address some of the provisions included in the Pipeline Safety Act of 2011, including increasing maximum civil penalties from $0.1 million to $0.2 million per violation per day of violation and from $1.0 million to $2.0 million as a maximum amount for a related series of violations as well as changing PHMSA’s enforcement process. While PHMSA has issued several notices of proposed rulemaking to implement the Pipeline Safety Act, many of these regulations were not finalized before funding expired at the end of 2015. On June 22, 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act became law and reauthorized funding for PHMSA until 2019. In addition to reauthorizing funding, the PIPES Act requires PHMSA to complete the rulemaking requirements set forth in the Pipeline Safety Act of 2011. The PIPES Act also requires, among other things, PHMSA to adopt safety standards for underground natural gas storage facilities and small scale liquefied natural gas pipeline facilities, imposes new reporting requirements on operators of hazardous liquid pipelines, and grants PHMSA to issue emergency orders to address unsafe conditions and practices that constitute imminent hazards.

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We may incur significant costs and liabilities resulting from implementing and administering pipeline and asset integrity programs and related repairs.

Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Safety Act of 2006 and the PIPES Act of 2016, the PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

This legislation has resulted in increased penalties for safety violations, additional safety requirements for newly constructed pipelines, new reporting requirements, expanded regulatory authority for PHMSA to address emergency conditions, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. New rules proposed by PHMSA, address many areas of this legislation. Extending the integrity management requirements to our gathering lines, among other regulatory requirements being considered by PHMSA, would impose additional obligations on us and could add material cost to our operations.

Climate change regulation at the federal, state or regional levels could result in increased operating and capital costs for us and reduced demand for our services.

The United States Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement was signed by President Obama on August 26, 2016 and requires participating countries to “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. It is not clear at this time if the Trump Administration will remain committed to the Paris Agreement. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA adopted two sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large stationary sources. The EPA has also expanded its existing GHG emissions reporting requirements to include upstream petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year. Some of our facilities are required to report under this rule, and operational and/or regulatory changes could require additional facilities to comply with GHG emissions reporting requirements. Furthermore, the EPA has finalized regulations that impose more stringent controls on methane and volatile organic compounds emissions from oil and gas development, production, and transportation operations. The EPA also has finalized regulations to impose greenhouse gas emission on the electric power sector, commonly referred to as the Clean Power Plan which, if implemented, could reduce the demand for fossil fuels. This regulation, however, remains the subject of an ongoing legal challenge and the Trump Administration has indicated that it may revisit, modify or revoke this rule, although the final outcome is uncertain at this time. In addition, almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, to acquire and surrender emission allowances with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved.

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RISKS ARISING FROM OUR PARTNERSHIP STRUCTURE AND RELATIONSHIPS WITH OUR GENERAL PARTNER AND ENBRIDGE MANAGEMENT

The interests of Enbridge may differ from our interests and the interests of our unitholders, and the board of directors of Enbridge Management may consider the interests of all parties to a conflict, not just the interests of our unitholders, in making important business decisions.

Enbridge indirectly owns all of the shares of our General Partner and all of the voting shares of Enbridge Management, and elects all of the directors of both companies. Furthermore, some of the directors and officers of our General Partner and Enbridge Management are also directors and officers of Enbridge. Consequently, conflicts of interest could arise between our unitholders and Enbridge.

Our partnership agreement limits the fiduciary duties of our General Partner to our unitholders. These restrictions allow our General Partner to resolve conflicts of interest by considering the interests of all of the parties to the conflict, including Enbridge Management’s interests, our interests and those of our General Partner. In addition, these limitations reduce the rights of our unitholders under our partnership agreement to sue our General Partner or Enbridge Management, its delegate, should its directors or officers act in a way that, were it not for these limitations of liability, would constitute breaches of their fiduciary duties.

We do not have any employees. In managing our business and affairs, we rely on employees of Enbridge, and its affiliates, who act on behalf of and as agents for us. A decrease in the availability of employees from Enbridge could adversely affect us.

Our partnership agreement and the delegation of control agreement limit the fiduciary duties that Enbridge Management and our General Partner owe to our unitholders and restrict the remedies available to our unitholders for actions taken by Enbridge Management and our General Partner that might otherwise constitute a breach of a fiduciary duty.

Our partnership agreement contains provisions that modify the fiduciary duties that our General Partner would otherwise owe to our unitholders under state fiduciary duty law. Through the delegation of control agreement, these modified fiduciary duties also apply to Enbridge Management as the delegate of our General Partner. For example, our partnership agreement:

These and similar provisions in our partnership agreement may restrict the remedies available to our unitholders for actions taken by Enbridge Management or our General Partner that might otherwise constitute a breach of a fiduciary duty.

Potential conflicts of interest may arise among Enbridge and its shareholders, on the one hand, and us and our unitholders and Enbridge Management and its shareholders, on the other hand. Because the fiduciary duties of the directors of our General Partner and Enbridge Management have been modified, the directors may be permitted to make decisions that benefit Enbridge and its shareholders or Enbridge Management and its shareholders more than us and our unitholders.

Conflicts of interest may arise from time to time among Enbridge and its shareholders, on the one hand, and us and our unitholders and Enbridge Management and its shareholders, on the other hand. Conflicts of interest may also arise from time to time between us and our unitholders, on the one hand, and Enbridge Management and its shareholders, on the other hand. In managing and controlling us as the delegate of our General Partner, Enbridge

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Management may consider the interests of all parties to a conflict and may resolve those conflicts by making decisions that benefit Enbridge and its shareholders or Enbridge Management and its shareholders more than us and our unitholders. The following decisions, among others, could involve conflicts of interest:

In these and similar situations, any decision by Enbridge Management may benefit one group more than another, and in making such decisions, Enbridge Management may consider the interests of all groups, as well as other factors, in deciding whether to take a particular course of action.

In other situations, Enbridge may take certain actions, including engaging in businesses that compete with us or are adverse to us and our unitholders. For example, although Enbridge and its subsidiaries are generally restricted from engaging in any business that is in direct material competition with our businesses, that restriction is subject to the following significant exceptions:

Since we were not engaged in any aspect of the natural gas business at the time of our initial public offering, Enbridge and its subsidiaries are not restricted from competing with us in any aspect of the natural gas business. In addition, Enbridge and its subsidiaries would be permitted to transport crude oil and liquid petroleum over routes that are not the same as our Lakehead system, even if such transportation is in direct material competition with our business.

We can issue additional common or other classes of units, including additional i-units to Enbridge Management when it issues additional shares, which would dilute the ownership interest of our unitholders.

The issuance of additional common or other classes of units by us, including the issuance of additional i-units to Enbridge Management when it issues additional shares may have the following effects:

Additionally, the public sale by our General Partner of a significant portion of the Class A or Class B common units, Class D units, Class E units or Series 1 preferred units that it or its subsidiary currently owns could reduce the market price of the Class A common units. Our partnership agreement allows the General Partner to

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cause us to register for public sale any units held by the General Partner or its affiliates. A public or private sale of the Class A or Class B common units, Class D units, Class E units or Series 1 preferred units currently held by our General Partner or its subsidiary could absorb some of the trading market demand for the outstanding Class A common units.

Holders of our limited partner interests have limited voting rights.

Our unitholders have limited voting rights on matters affecting our business, which may have a negative effect on the price at which our common units trade. In particular, the unitholders did not elect our General Partner or the directors of our General Partner or Enbridge Management and have no rights to elect our General Partner or the directors of our General Partner or Enbridge Management on an annual or other continuing basis. Furthermore, if unitholders are not satisfied with the performance of our General Partner, they may find it difficult to remove our General Partner. Under the provisions of our partnership agreement, our General Partner may be removed upon the vote of at least 66.67% of the outstanding common units (excluding the units held by the General Partner and its affiliates) and a majority of the outstanding i-units voting together as a separate class (excluding the number of i-units corresponding to the number of shares of Enbridge Management held by our General Partner and its affiliates). Such removal must, however, provide for the election and succession of a new general partner, who may be required to purchase the departing general partner interest in us in order to become the successor general partner. Such restrictions may limit the flexibility of the limited partners in removing our general partner, and removal may also result in the general partner interest in us held by the departing general partner being converted into Class A common units.

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

Our Class A common units are listed on the NYSE. The NYSE does not require us to have, and we do not intend to have, a majority of independent directors on the boards of our General Partner or Enbridge Management, or to establish a compensation committee or nominating and corporate governance committee. In addition, any future issuance of additional Class A common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to corporations. Accordingly, holders of our Class A common units will not have the same protections afforded to investor owners of certain corporations that are subject to all of the NYSE corporate governance requirements.

We are a holding company and depend entirely on our operating subsidiaries’ distributions to service our debt obligations.

We are a holding company with no material operations. If we cannot receive cash distributions from our operating subsidiaries, we will not be able to meet our debt service obligations. Our operating subsidiaries may from time to time incur additional indebtedness under agreements that contain restrictions, which could further limit each operating subsidiaries’ ability to make distributions to us.

The debt securities we issue and any guarantees issued by any of our subsidiaries that are guarantors will be structurally subordinated to the claims of the creditors of any of our operating subsidiaries who are not guarantors of the debt securities. Holders of the debt securities will not be creditors of our operating subsidiaries who have not guaranteed the debt securities. The claims to the assets of these non-guarantor operating subsidiaries derive from our own ownership interest in those operating subsidiaries. Claims of our non-guarantor operating subsidiaries’ creditors will generally have priority as to the assets of such operating subsidiaries over our own ownership interest claims and will therefore have priority over the holders of our debt, including the debt securities. Our non-guarantor operating subsidiaries’ creditors may include:

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Enbridge Management’s discretion in establishing our cash reserves gives it the ability to reduce the amount of cash available for distribution to our unitholders.

Enbridge Management may establish cash reserves for us that in its reasonable discretion are necessary to fund our future operating and capital expenditures, provide for the proper conduct of business, and comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves affect the amount of cash available for distribution to holders of our common units.

Holders of our Series 1 Preferred Units have a distribution preference, which may adversely affect the value the Class A common units

The holders of our Series 1 Preferred Units, or Preferred Units, have a preferential right to distributions prior to distributions to the holders of our Class A common units. Through the quarter ending June 30, 2018, the quarterly distributions will not be payable on the Preferred Units and instead will accrue and accumulate. The accrued amounts will be paid in equal amounts over a twelve-quarter period beginning with the first quarter of 2019. Thereafter, the distributions will be paid in cash on a quarterly basis. To the extent that we do not pay in full any distribution on the Preferred Units, the unpaid amount will accrue and accumulate until it is paid in full, and no distributions may be made on the common units during that time.

Total insurance coverage for multiple insurable incidents exceeding coverage limits would be allocated by our General Partner on an equitable basis.

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates through the policy renewal date of May 1, 2017. The comprehensive insurance program also includes property insurance coverage on our assets, except pipeline assets that are not located at major water crossings, including earnings interruption resulting from an insurable event. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement the Partnership has entered into with Enbridge, MEP, and another Enbridge subsidiary.

RISKS RELATED TO OUR DEBT AND OUR ABILITY TO MAKE DISTRIBUTIONS

Agreements relating to our debt restrict our ability to make distributions, which could adversely affect the value of our Class A common units, and our ability to incur additional debt and otherwise maintain financial and operating flexibility.

MEP is restricted by its credit facility from making distributions to us. MEP and Midcoast Operating are restricted by their revolving credit facility from declaring or making distributions to us if a revolving credit facility payment, insolvency or financial covenant default then exists or any other default then exists which permits the lenders to accelerate the revolving credit facility. However, if no such defaults exist when such distribution is declared, MEP and Midcoast are permitted to make distributions to us even if any such defaults exist when the distribution is made unless MEP or any of its subsidiaries has knowledge that the revolving credit facility has been accelerated.

In addition, we are prohibited from making distributions to our unitholders during (1) the existence of certain defaults under our Credit Facilities or (2) during a period in which we have elected to defer interest payments on the Junior Notes, subject to limited exceptions as set forth in the related indenture. Further, the agreements governing our Credit Facilities may prevent us from engaging in transactions or capitalizing on business opportunities that we believe could be beneficial to us by requiring us to comply with various covenants, including the maintenance of certain financial ratios and restrictions on:

Although the indentures governing our senior notes do not limit our ability to incur additional debt, they impose restrictions on our ability to enter into mergers or consolidations and sales of all or substantially all of our assets, to incur liens to secure debt and to enter into sale and leaseback transactions. A breach of any restriction under our Credit Facilities or our indentures could permit the holders of the related debt to declare all amounts outstanding under those agreements immediately due and payable and, in the case of our Credit Facilities, terminate

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all commitments to extend further credit. Any subsequent refinancing of our current debt or any new indebtedness incurred by us or our subsidiaries could have similar or greater restrictions.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our partners if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

We are exposed to restrictions on the ability of Midcoast Operating to repay indebtedness owed to us and MEP and Midcoast Operating to make distributions to us.

We, as financial support provider, entered into a financial support agreement with Midcoast Operating, pursuant to which we will provide letters of credit and guarantees, not to exceed $700 million in the aggregate at any time outstanding, in support of the financial obligations of Midcoast Operating and its wholly owned subsidiaries under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. Our rights to payments under the financial support agreement are subordinated to the rights of the lenders under the private placement debt of MEP and the revolving credit facility of MEP and Midcoast Operating during the continuation of a default under their revolving credit facility. If Midcoast Operating experiences financial or other problems and fails to comply with the covenants under their revolving credit facility, it would limit our ability to receive payment of amounts owed to us under this agreement.

In addition, MEP and Midcoast Operating are restricted under their revolving credit facility and MEP’s note purchase agreement from making distributions to us in certain circumstances involving certain defaults thereunder or any events of defaults thereunder. It is likely that MEP may not be able to meet the total leverage ratio financial covenant under those agreements at some point during the term of the agreements without further action. If this were to occur, MEP would seek to take action to prevent a default, although there is no assurance that it would be successful. Any inability of MEP or Midcoast Operating to make distributions, or of Midcoast Operating to repay its indebtedness to us, could reduce our cash flows and affect our results of operations.

TAX RISKS TO COMMON UNITHOLDERS

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation for state tax purposes, then our distributable cash flow to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a publicly-traded partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

Section 7704 of the Internal Revenue Code of 1986, or the Internal Revenue Code, provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. An exception exists, however, with respect to a publicly-traded partnership for which 90% or more of the gross income for every taxable year consists of “qualifying income.” If less than 90% of our gross income for any taxable year is qualifying income, we will be taxed as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent tax years. Although we do not believe that we will be treated as a corporation for

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federal income tax purposes based on our current operations, the IRS could disagree with the positions we take. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced.

In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax on our gross income apportioned to Texas.

Imposition of any such taxes may substantially reduce the cash we have available for distribution. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation for state tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that, if a law is enacted that subjects us to taxation as a corporation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

The tax treatment of publicly-traded partnerships could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly-traded partnerships.

Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. It is possible, however, that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

On January 24, 2017, the U.S. Treasury Department issued final regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the final regulations affect our ability to qualify as a publicly traded partnership.

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to the unitholder. This allocation of taxable income may require the payment of federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we have taken or may take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our positions and such positions may not ultimately be sustained. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on

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the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our distributable cash flow.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the tax basis of the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, or UBTI, and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in more tax to you and may adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge could also affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Treasury Department recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of our method. If the IRS were to challenge our method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may be required to recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for

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federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We have adopted certain valuation methodologies for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our General Partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our General Partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has a publicly-traded partnership technical termination relief program whereby, if a publicly-traded partnership that technically terminated requests publicly-traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

As a result of investing in our common units, unitholders may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in several states. Most of these states currently impose a personal income tax on individuals. As we make acquisitions or

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expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is a unitholder’s responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Generally, we may elect to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be effective in all circumstances and the manner in which the election is made and implemented has yet to be determined. If we are unable to have our general partner and our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. These rules are not applicable to us for tax years beginning on or prior to December 31, 2017.

Item 2. Properties

Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are included in Item 1. Business, which is incorporated herein by reference.

In general, our systems are located on land owned by others and are operated under perpetual easements and rights-of-way, licenses, leases or permits that have been granted by private land owners, public authorities, railways or public utilities. Our liquids systems have pumping stations, tanks, terminals and certain other facilities that are located on land that is owned by us in fee and/or used by us under easements, licenses, leases or permits. Additionally, our natural gas systems have natural gas compressor stations, processing plants and treating plants, the vast majority of which are located on land that is owned by us, with the remainder used by us under easements, leases or permits.

Titles to our properties acquired in our natural gas systems are subject to encumbrances in some cases. We believe that none of these burdens should materially detract from the value of these properties or materially interfere with their use in the operation of our business.

Item 3. Legal Proceedings

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition. The disclosures included in Part II, Item 8. Financial Statements and Supplementary Data, under Note 25. Commitments and Contingencies, address the matters required by this item and are incorporated herein by reference.

Item 4. Mine Safety Disclosures

None.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Our Class A common units are listed and traded on the NYSE, the principal market for the Class A common units, under the symbol “EEP.” The quarterly price ranges per Class A common unit and cash distributions paid per unit for 2016 and 2015 are summarized as follows:

		First				Second				Third				Fourth
2016 Quarters
High		$	24.22			$	23.46			$	25.49			$	26.37
Low		$	14.27			$	16.86			$	21.97			$	21.78
Cash distributions paid		$	0.58300			$	0.58300			$	0.58300			$	0.58300
2015 Quarters
High		$	41.39			$	38.53			$	34.49			$	29.99
Low		$	35.07			$	32.93			$	22.40			$	19.31
Cash distributions paid		$	0.57000			$	0.57000			$	0.58300			$	0.58300

On February 14, 2017, the last reported sales price of our Class A common units on the NYSE was $18.28. As of January 20, 2017, there were approximately 929 registered holders of record of Class A common units. The number of registered holders does not include unitholders whose units are held in trust by other entities. There is no established public trading market for our Series 1 Preferred units, Class B common units, Class D units, Class E units or Incentive Distribution Units, or IDUs, all of which are held directly or indirectly by the General Partner, or our i-units, all of which are held by Enbridge Management.

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Item 6. Selected Financial Data

The following table sets forth, for the periods and at the dates indicated, the summary historical financial data. The table is derived, and should be read in conjunction with, our audited consolidated financial statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

		December 31,
		2016(1)				2015(1)				2014				2013				2012
		(in millions, except per unit amounts)
Income Statement Data:
Operating revenues(2)		$	4,481.9			$	5,146.1			$	7,964.7			$	7,117.1			$	6,706.1
Operating expenses(2)(3)(4)(5)			4,153.8				4,464.5				6,878.0				6,676.7				5,812.9
Operating income			328.1				681.6				1,086.7				440.4				893.2
Interest expense			(445.5	)			(322.0	)			(403.2	)			(320.4	)			(345.0	)
Allowance for equity used during construction(6)			45.5				70.3				57.2				43.1				11.2
Other income (expense)			31.5				29.3				8.9				16.0				(1.2	)
Income tax expense			(0.9	)			(4.9	)			(9.6	)			(18.7	)			(8.1	)
Net income (loss)			(41.3	)			454.3				740.0				160.4				550.1
Less: Noncontrolling interest			26.4				221.1				263.3				88.3				57.0
Series 1 preferred unit distributions			90.0				90.0				90.0				58.2				—
Accretion of discount on Series 1 preferred units			4.7				11.2				14.9				9.2				—
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	(162.4	)		$	132.0			$	371.8			$	4.7			$	493.1
Net income (loss) allocable to common units and i-units		$	(376.5	)		$	(84.8	)		$	218.4			$	(122.7	)		$	369.2
Net income (loss) per common unit and i-unit (basic and diluted)(7)		$	(1.08	)		$	(0.25	)		$	0.67			$	(0.39	)		$	1.27
Cash distributions paid per limited partner unit outstanding		$	2.3320			$	2.3060			$	2.1970			$	2.1740			$	2.1520
Financial Position Data (at year end):
Property, plant and equipment, net		$	16,722.6			$	17,412.4			$	15,692.7			$	13,176.8			$	10,937.6
Total assets(8)			18,110.1				18,774.3				17,726.5				14,880.5				12,773.0
Long-term debt, excluding current maturities(8)(9)			7,884.4				7,728.4				6,654.8				4,756.4				5,477.9
Note payable to General Partner			750.0				—				306.0				318.0				330.0
Partners’ capital:
Series 1 preferred units(10)			1,191.5				1,186.8				1,175.6				1,160.7				—
Class D units(11)			2,517.6				2,517.6				2,516.8				—				—
Class E units(12)			778.2				778.2				—				—				—
Class A common units(13)			—				—				235.5				2,979.0				3,590.2
Class B common units			—				—				—				65.3				83.9
i-units(14)			—				212.6				712.6				1,291.9				801.8
Incentive distribution units(15)			495.2				495.0				493.0				—				—
General Partner			(666.8	)			147.4				198.3				301.5				299.0
Accumulated other comprehensive loss			(339.3	)			(370.0	)			(211.4	)			(76.6	)			(320.5	)
Noncontrolling interest			3,846.1				3,944.5				3,609.0				1,975.6				793.5
Partners’ capital		$	7,822.5			$	8,912.1			$	8,729.4			$	7,697.4			$	5,247.9
Cash Flow Data:
Cash flows provided by operating activities(3)(4)(5)		$	1,415.7			$	1,030.8			$	816.8			$	1,212.4			$	851.0
Cash flows used in investing activities		$	1,066.3			$	2,126.4			$	2,976.6			$	2,642.9			$	1,906.6
Cash flows provided by (used in) financing activities activities(9)(10)(11)(12)(13)(14)(15)		$	(388.7	)		$	1,045.8			$	2,192.9			$	1,367.4			$	860.6
Additions to property, plant and equipment, and acquisitions included in investing activities, net of cash acquired		$	1,091.3			$	2,201.8			$	2,933.8			$	2,410.8			$	1,739.9

Date of Acquisition or Disposition		Description of Acquisition or Disposition
August 2016		MEP disposition of trucks, trailers and related facilities
July 2015		MEP disposition of propylene pipeline
July 2015		MEP disposition of Tinsley crude oil pipeline, storage facilities and docks
February 2015		MEP acquisition of a Texas midstream business

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Date of Debt Issuance		Debt Type				Amount of Debt Issuance
October 2015			4.375% Senior Notes			$	500
October 2015			5.875% Senior Notes			$	500
October 2015			7.375% Senior Notes			$	600
September 2014			3.560% MEP Senior Notes			$	75
September 2014			4.040% MEP Senior Notes			$	175
September 2014			4.420% MEP Senior Notes			$	150

Date of Unit Issuance		Class of Limited Partnership Interest				Number of Units Issued				Net Proceeds Including General Partner Contribution
March 2015			Class A				8,000,000			$	294.8
September 2012			Class A				16,100,000			$	456.2
May 2012			Class A				64,464			$	2.0

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Fiscal Year		Amount of Distribution of i-units to i-unit Holders(a)				Retained from General Partner				Distribution of Cash
2016		$	179.1			$	3.7			$	864.2
2015		$	161.2			$	3.3			$	835.9
2014		$	143.9			$	3.0			$	727.8
2013		$	113.8			$	2.3			$	708.9
2012		$	85.0			$	1.7			$	660.3

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

Strategic Review

Our ultimate parent, Enbridge, recently announced a merger with Spectra Energy Corp. Enbridge has indicated that as part of the integration of the two companies, its U.S. sponsored vehicles, including us, will be reviewed in context of the combined enterprise. In addition, under the merger agreement, Enbridge has agreed that it and its subsidiaries, including us, will conduct their businesses in the ordinary course prior to completing the merger transaction, subject to certain specified exceptions or the consent of Spectra Energy Corp.

We and Enbridge have previously announced that our strategic review is ongoing with the objectives of improving our financial position and future outlook. On January 26, 2017, our Board approved three initial strengthening actions which together alleviate short-term capital expenditure requirements and enhance our cash flows. First, our Board of Directors approved a joint funding arrangement with our General Partner for the U.S. L3R Program whereby our General Partner paid us approximately $450 million for a 99% interest in the project, including our share of the construction costs to date and other incremental amounts. Through this arrangement, we maintain a strong cash-generating significant opportunity to invest in a strategic growth project, while obtaining relief from funding requirements during the construction period. Refer to Future Prospects for Liquids — Line 3 Replacement Program for further details.

Second, we utilized the funds received from the U.S. L3R Program to exercise our option under the Eastern Access joint funding agreement to acquire an additional 15% interest in the Eastern Access Projects, at its book value of approximately $360 million, which is now in service. The additional interest is expected to generate additional cash flows and is highly complementary to our existing core liquids pipeline business. Refer to Future Prospects for Liquids — Eastern Access Projects for further details.

Third, MEP entered into the Merger Agreement with our General Partner whereby our General Partner will acquire, for cash, all of the outstanding publicly held Class A common units of MEP. This action enables us to retain more of our cash flow, reduces our costs associated with an additional public company and simplifies our corporate structure. Refer to Future Prospects for Natural Gas for further details.

Our strategic review is ongoing and considering: (i) the sustainability of our current level of distributions to unitholders, (ii) further cost efficiency measures, (iii) the potential extension of existing supportive actions by Enbridge, (iv) the sale of a portion or all of our remaining interests in the natural gas gathering and processing assets, including to Enbridge, and; (v) potential further restructuring of the general partner incentive distribution rights. Enbridge has indicated that at this time it is not planning a buy-in of us and that it expects that we will remain a publicly-traded limited partnership subsequent to the strategic review and resulting actions. The review is expected to continue into the second quarter of 2017.

RESULTS OF OPERATIONS — OVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following activities:

We conduct our business through two business segments: Liquids and Natural Gas. Our Liquids segment includes the operations of our Lakehead, Mid-Continent and North Dakota systems. These systems largely consist of Federal Energy Regulatory Commission, or FERC, regulated interstate crude oil and liquid petroleum pipelines, gathering systems and storage facilities. The Lakehead system, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. Our Liquids systems generate revenues primarily from charging shippers a rate per barrel to gather, transport and store crude oil and liquid petroleum.

Our Natural Gas segment includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. Moreover, our Natural Gas segment also provides supply, transmission, storage and sales services to producers and wholesale customers on

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our natural gas gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Revenues for our Natural Gas segment 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. Segment gross margin is derived from the compensation we receive from customers in the form of fees or commodities we receive for providing services in addition to the proceeds we receive for sales of natural gas, NGLs and condensate to affiliates and third-parties.

The following table reflects our operating income by business segment and corporate charges for each of the years ended December 31, 2016, 2015 and 2014:

		December 31,
		2016				2015				2014
		(in millions)
Operating income (loss)
Liquids		$	490.8			$	994.0			$	938.9
Natural Gas			(149.0	)			(298.0	)			158.4
Other			(13.7	)			(14.4	)			(10.6	)
Total operating income			328.1				681.6				1,086.7
Interest expense			(445.5	)			(322.0	)			(403.2	)
Allowance for equity used during construction			45.5				70.3				57.2
Other income			31.5				29.3				8.9
Income (loss) before income tax expense			(40.4	)			459.2				749.6
Income tax expense			(0.9	)			(4.9	)			(9.6	)
Net income (loss)			(41.3	)			454.3				740.0
Less: Net income attributable to:
Noncontrolling interest			26.4				221.1				263.3
Series 1 preferred unit distributions			90.0				90.0				90.0
Accretion of discount on Series 1 preferred units			4.7				11.2				14.9
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	(162.4	)		$	132.0			$	371.8

Highlights

Liquids

Our Liquids segment operating income decreased $503.2 million for the year ended December 31, 2016, as compared with the same period in 2015, primarily as a result of an impairment loss of $756.7 million on the Sandpiper Project that was recognized during the third quarter of 2016. The decrease in operating income was partially offset by increased revenues from additional assets placed in service and an increase in volumes on our systems. In 2015, $1.6 billion of additional assets were placed into service on our Lakehead system, including portions of the Eastern Access, Mainline Expansion and other projects. Average daily volumes delivered on our liquids systems increased 260,000 Bpd, or 9.0%, for the year ended December 31, 2016, when compared with the same period in 2015, due to increased capacity from the expansions mentioned above.

Natural Gas

Our Natural Gas segment operating loss decreased $149.0 million for the year ended December 31, 2016, as compared to the same period in 2015, primarily due to a goodwill impairment charge of $246.7 million recognized during the year ended December 31, 2015. No similar charge was recorded during the same period in 2016. The reduction in impairment charges was partially offset by reduced natural gas production volumes due to the commodity price environment for natural gas, NGLs, condensate and crude oil which continues to impact production volumes. The average daily volumes of our major systems for the year ended December 31, 2016 decreased by approximately 285,000 million British thermal units per day, or MMBtu/d, or 14%, as compared to the same period in 2015 and the average NGL production for the year ended December 31, 2016, decreased 12,789 Bpd, or 16%, as compared to the same period in 2015.

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Derivative Transactions and Hedging Activities

Contractual arrangements expose us to market risks associated with changes in (1) commodity prices where we receive crude oil, natural gas or NGLs in return for the services we provide or where we purchase natural gas or NGLs and (2) interest rates on our variable rate debt. Our unhedged commodity position is fully exposed to fluctuations in commodity prices, which can be significant during periods of price volatility. We use derivative financial instruments such as futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in commodity prices and interest rates, as well as to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. Derivative financial instruments that do not receive hedge accounting under the provisions of authoritative accounting guidance create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not receive hedge accounting in our consolidated statements of income as follows:

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

		December 31,
		2016				2015				2014
		(in millions)
Liquids segment:
Non-qualified hedges		$	(8.7	)		$	(15.5	)		$	13.6
Natural Gas segment:
Hedge ineffectiveness			—				(4.1	)			5.6
Non-qualified hedges			(112.1	)			(54.2	)			152.9
Commodity derivative fair value net gains (losses)			(120.8	)			(73.8	)			172.1
Other:
Interest rate hedge ineffectiveness			(6.5	)			98.9				(100.1	)
Derivative fair value net gains (losses)		$	(127.3	)		$	25.1			$	72.0

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RESULTS OF OPERATIONS — BY SEGMENT

Liquids

Our Liquids segment includes the operations of our Lakehead, North Dakota and Mid-Continent systems. We provide a detailed description of each of these systems in Item 1. Business. The following table sets forth the operating results and statistics of our Liquids segment assets for the periods presented:

		December 31,
		2016				2015				2014
		(in millions)
Operating Results:
Operating revenue		$	2,515.9			$	2,303.4			$	2,070.4
Operating expenses:
Environmental costs, net of recoveries			2.2				3.1				97.3
Operating and administrative			561.9				605.9				500.8
Power			277.4				259.5				226.6
Depreciation and amortization			426.5				378.4				306.8
Asset Impairment			757.1				62.5				—
Total operating expenses			2,025.1				1,309.4				1,131.5
Operating income		$	490.8			$	994.0			$	938.9
Operating Statistics
Lakehead system:
United States(1)			1,968				1,869				1,669
Canada(1)			606				446				444
Total Lakehead system delivery volumes(1)			2,574				2,315				2,113
Barrel miles (billions)			724				640				582
Average haul (miles)			768				757				755
Mid-Continent system delivery volumes(1)			188				212				200
North Dakota system:
Trunkline(1)			378				351				315
Gathering(1)			—				2				3
Total North Dakota system delivery volumes(1)			378				353				318
Total Liquids segment delivery volumes(1)			3,140				2,880				2,631

Year ended December 31, 2016 compared with year ended December 31, 2015

Operating income of our Liquids segment for the year ended December 31, 2016, decreased $503.2 million, as compared with the same period in 2015, primarily due to increased impairment charges of $694.6 million. During the year ended December 31, 2016, we recorded a $756.7 million impairment loss on the Sandpiper Project. For further details, see Future Prospects Updates for Liquids — Recent Developments — Sandpiper Project. During the year ended December 31, 2015, we recorded a $62.5 million impairment loss to write off the remaining carrying value of our Berthold rail facility due to contracts that were not renewed.

Operating revenues of our Liquids segment increased $212.5 million for the year ended December 31, 2016, as compared to the same period in 2015. Operating revenue on the Lakehead system increased $247.2 million for the year ended December 31, 2016, as compared with the same period in 2015, primarily due to an increase of $207.7 million from increased surcharge revenue for projects subject to regulatory accounting. This increase is a result of placing $1.6 billion of additional assets into service on the Lakehead system in 2015. These additional assets placed into service included components of the Eastern Access, Mainline Expansion, and other expansion projects. These amounts were partially offset by a $71.8 million decrease in rates due to greater qualifying volume credits related to Lakehead toll revenues and an $11.7 million decrease due to a surcharge adjustment that was retrospectively adopted on January 1, 2016.

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The Lakehead system experienced a period over period increase of 259,000 Bpd in average daily delivery volumes, which resulted in an $105.3 million increase in operating revenues period over period. Increased volumes on the Lakehead system were a result of additional system capacity from the assets that were placed into service, as mentioned above, and increased downstream demand from the completion of certain Enbridge Light Oil Market Access Program projects that expanded access to markets in the Midwest and Eastern Canada for growing volumes of light oil production.

The increase in operating income on the Lakehead system was offset by an approximate $21 million decrease due to the impact of extreme wildfires in northeastern Alberta during the year ended December 31, 2016, as compared to the same period in 2015. The impact of the wildfires during the first week of May 2016 in northeastern Alberta hindered throughput in the second quarter of 2016 as certain upstream facilities were temporarily shut down resulting in disruption of service on the Lakehead System. The reduced system deliveries decreased operating revenue by approximately $30 million and power costs by approximately $9 million for the year ended December 31, 2016. Oil sands production substantially came back online by the end of June 2016.

Operating revenue on the North Dakota system decreased $37.5 million for the year ended December 31, 2016, as compared with the same period in 2015, primarily due to lower average rates and lower rail revenues. Operating revenues on the Berthold rail facility decreased $24.5 million as a result of expired contracts. In addition, North Dakota system operating revenues decreased $14.5 million as certain surcharge rates subject to an annual adjustment were decreased effective April 1, 2016 and 2015. Two of those surcharges, the Phase 5 Looping and the Phase 6 Mainline surcharges, accounted for $18.5 million of the decrease. These two surcharges, which expired at the end of 2016, accounted for $31.0 million of total operating revenues in 2016.

Offsetting these decreases in operating revenue on the North Dakota system was an increase in operating revenue of $7.2 million from an increase of 25,000 Bpd in average daily delivery volumes. Increased volumes on the North Dakota system were also a result of increased downstream demand from the completion of certain Enbridge Light Oil Market Access Program projects and by volumes shifting from other higher cost alternatives such as transportation by rail.

Environmental costs, net of recoveries, decreased $0.9 million for the year ended December 31, 2016 when compared with the same period in 2015. This decrease is primarily related to an $8.0 million decrease in the Line 6B crude oil release accrual due to optimization of our remedial investigation reporting and savings related to our residual oil monitoring and maintenance in the fourth quarter of 2016 and $10.0 million in insurance recoveries associated with the Line 6A crude oil release in the third quarter of 2016. No similar activity occurred during the same period of 2015. This decrease is primarily offset by a $15.0 million increased cost accrual in the first quarter of 2016 for estimated fines and penalties associated with the Line 6B crude oil release.

The decrease of $44.0 million in operating and administrative expenses period over period was primarily due to a decrease of $66.2 million in pipeline integrity costs. The decrease in pipeline integrity costs relates to $79.1 million for the year ended December 31, 2015 for the hydrostatic test on Line 2B. There were no such costs for the year ended December 31, 2016. This decrease was offset by an increase of $25.5 million in property tax expense. This cost increase primarily resulted from the additional assets placed into service as discussed above. The decrease was also partially offset by $9.0 million in Sandpiper Project related costs.

Power costs increased $17.9 million for the year ended December 31, 2016 when compared with the year ended 2015, primarily as a result of increased volumes on our systems.

The increase in depreciation expense of $48.1 million for the year ended December 31, 2016, when compared with the same period in 2015, is directly attributable to additional assets placed into service, primarily on projects discussed above.

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Year ended December 31, 2015 compared with year ended December 31, 2014

Operating income of our Liquids segment for the year ended December 31, 2015, increased $55.1 million, as compared with the same period in 2014, primarily due to the reasons discussed below.

Operating revenue increased $233.0 million for the year ended December 31, 2015, when compared with the same period in 2014. Operating revenue increased $25.2 million, due to higher average rates. Operating revenue also increased $223.8 million from increased surcharge revenue for projects on our Lakehead system subject to regulatory accounting, primarily as a result of placing $2.7 billion and $1.6 billion of assets into service on the Lakehead system in 2014 and 2015, respectively. These additional assets placed into service included components of the Eastern Access, Mainline Expansion Projects and other expansion projects. This amount was partially offset by a $101.4 million decrease in rates due to greater qualifying volume credits related to Lakehead toll revenues. Qualifying volume credits represent a contractual obligation, which were introduced with the original Southern Access and Alberta Clipper expansions, to return a portion of revenue to our shippers when volumes shipped exceed certain predetermined levels. Once these predetermined levels are exceeded, the expansion projects are earning their full cost-of-service. Hence, to limit project earnings to agreed levels, the credits are returned to the shippers through the tolls.

Operating revenue also increased $87.0 million due to increased average daily delivery volumes. Volumes delivered increased 249,000 Bpd, of which 202,000 Bpd and $72.3 million were attributable to higher volumes on our Lakehead system as a result of additional system capacity from the aforementioned assets that were placed into service. The North Dakota system experienced an increase of 35,000 Bpd and $12.7 million in revenues due to our system’s enhanced market access in addition to volumes shifting onto this system and away from higher cost alternatives such as transportation by rail. Additionally, our operating revenue also increased by $25.0 million due to a surcharge that went into effect on April 1, 2015, which is designed to recover half of the costs of a hydrostatic test on Line 2B.

Increases to operating revenue were also partially offset by decreased non-cash, mark-to-market net gains of $28.4 million related to derivative financial instruments. The decrease is primarily the result of a $19.4 million reclassification of previously recognized unrealized mark-to-market net gains where the underlying transactions were settled, coupled with $9.0 million of decreased non-cash, mark-to-market net gains due to smaller decreases in average forward prices during 2015 than during 2014.

Environmental costs, net of recoveries, decreased $94.2 million for the year ended December 31, 2015 when compared with the same period in 2014. This decrease is primarily related to cost accruals for the Line 6B crude oil release. During the year ended December 31, 2015, there were no cost accruals for the Line 6B crude oil release. For the same period ended 2014, there were $85.9 million of cost accruals.

Operating and administrative expenses increased $105.1 million for the year ended December 31, 2015, when compared with the same period in 2014, primarily due to $64.2 million of pipeline integrity costs. The increase in pipeline integrity costs is primarily due to $79.1 million of costs in 2015 for the hydrostatic test on Line 2B. Pipeline integrity costs were partially offset by a $14.9 million decrease in other integrity costs.

Additionally, the increase in operating and administrative expenses was also due to cost increases of $18.9 million of property taxes, $15.3 million of workforce related costs and $6.8 million of other operating and administrative expenses, mainly consisting of contract labor, insurance, rents and lease payments, and professional and regulatory services. These cost increases primarily result from the additional assets placed into service during 2014 and 2015.

Power costs increased $32.9 million for the year ended December 31, 2015 when compared with the year ended 2014, primarily as a result of increased volumes on our systems.

During the year ended December 31, 2015, we recorded a non-cash impairment loss of $62.5 million to write off the remaining carrying value of our Berthold rail facility due to contracts that were not renewed subsequent to 2016. There were no such asset impairment charges for the year ended December 31, 2014.

The increase in depreciation expense of $71.6 million for the year ended December 31, 2015, when compared with the same period in 2014, is directly attributable to additional assets placed into service, primarily on projects discussed above.

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Future Prospects Update for Liquids

We currently have a multi-billion dollar growth program underway, with projects coming into service in 2019, in addition to options to increase our economic interest in projects that are jointly funded by Enbridge and us. On January 27, 2017, we announced two initial strengthening actions are being undertaken in our liquids business, which together alleviate short-term capital expenditure requirements and enhance our cash flows.

Recent Developments

Bakken Pipeline System

On August 2, 2016, we announced that we had entered into an agreement with Marathon Petroleum Corporation, or MPC, to form a new joint venture, MarEn Bakken Company LLC, or MarEn, which in turn had entered into an agreement with Bakken Holdings Company LLC, or Bakken Holdings, an affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P., to, among other things, acquire a 49% equity interest in Bakken Pipeline Investments LLC, or BPI. BPI owns 75% of the Bakken Pipeline System. Under this arrangement, we and MPC indirectly hold 75% and 25%, respectively, of the joint venture’s 49% interest in BPI. This transaction was closed on February 15, 2017. The purchase price of our effective 27.6% interest in the Bakken Pipeline was $1.5 billion.

We funded the $1.5 billion acquisition through a bridge loan provided by an affiliate of our General Partner. The bridge loan will remain in place until a joint funding arrangement with our General Partner is finalized. A special committee of independent directors of the board of Enbridge Management has been established to consider a proposal from our General Partner, on behalf of Enbridge, that would establish a joint funding arrangement for this investment. This arrangement remains subject to the review of the conflicts committee of the Board of our General Partner.

The Bakken Pipeline System, which consists of the Dakota Access Pipeline, or DAPL, and the Energy Transfer Crude Oil Pipeline, or ETCOP, projects, will transport crude oil from the Bakken formation in North Dakota to markets in eastern PADD II and the U.S. Gulf Coast. DAPL consists of 1,172 miles of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. It is expected to initially deliver in excess of 470,000 Bpd of crude oil and has the potential to be expanded to 570,000 Bpd. ETCOP consists of 62 miles of new 30-inch diameter pipe, 686 miles of converted 30-inch diameter pipe, and 40 miles of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas.

Sandpiper Project

On September 1, 2016, we announced that we applied for the withdrawal of regulatory applications for the Sandpiper Project pending with the Minnesota Public Utilities Commission, or MNPUC, because we concluded that the project should be delayed until such time as crude oil production in North Dakota recovers sufficiently to support development of new pipeline capacity. Based on updated projections, we expect that this pipeline capacity will not likely be needed until beyond our current five-year planning horizon. On October 28, 2016, the MNPUC approved our application to withdraw the regulatory applications without conditions and issued the written order on November 10, 2016.

In connection with the above announcement and other factors, we evaluated the Sandpiper Project for impairment and determined that the project was impaired. In the third quarter of 2016, we recorded an asset impairment of $762.6 million, including related project costs. Of the total amount, $269.6 million was attributable to noncontrolling interest with respect to MPC’s ownership interests, and $493.0 million was attributable to our general and limited partner ownership interests. For further details, see Item 1. Financial Statements, Note 11. Property, Plant and Equipment.

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Regulatory Permitting

Our multi-billion dollar growth program includes investments in joint ventures as described above and organic growth projects. In recent years, proposed projects in our industry have faced unexpected extensions in the regulatory permitting process, which has created delays in and uncertainty related to timing of certain projects. Delays in the in service dates of our projects may have a significant impact on our forecasts and our financial results.

In addition environmental and indigenous opposition to the construction and operation of pipelines has impacted the industry, including Enbridge. We undertake in extensive engagements with all stakeholders that are impacted by our projects in order to meet the needs of the public and ensure that issues are identified and managed. This effort includes land owners, communities, all levels of government and Tribal leadership, regulators and permitting agencies.

Renewal of Line 5 Easement

On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians, or the Band, voted not to renew its interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within the Lakehead system. The Band’s resolution calls for decommissioning and removal of the pipeline from all Bad River lands and watershed. The Tribal Resolution may impact Enbridge’s ability to operate the pipeline on the Reservation. Since the Band passed the resolution, the parties have held discussions about the possiblity of engaging in a facilitated mediation process, with the objective of resolving the Band’s concerns on a long-term basis.

Impact of Commodity Price Declines

Volatility in commodity prices can impact production volumes in the oil sands region of Western Canada and the Bakken region of North Dakota, our two primary crude oil supply basins.

The relatively high costs and large up-front capital investments required by oil sands projects involve significant assumptions around short-term and long-term crude oil fundamentals, including world supply and demand, North American supply and demand, and price outlook, among many other factors. As oil sands production is long-term in nature, the long-term outlook is significant to a producer’s investment decision. In the near-term, the current pricing environment is not expected to impact projected growth from the oil sands region.

Declines in the crude oil price downturn may result in deferral of some oil sands projects. However, we expect that projects already under construction will be finished and enter production. In addition, current production volumes from the oil sands are unlikely to decrease absent an operational upset at any of the oil sands operations. Accordingly, we do not anticipate significant changes in our short-term crude oil volume outlook. Our long-term growth in volumes and additional infrastructure expansion will depend on long-term fundamentals. During this period of uncertainty, we believe our pipeline systems are positioned to capture incremental pipeline capacity needs with lower cost, smaller scale expansions of our large Lakehead pipeline system. Financial impacts to our Lakehead pipeline system, in the event the rate of growth were to slow or volumes were to decline, is muted by our cost-of-service agreements, toll structures and demand to transport crude oil from existing production.

Tight sands oil production in any basin in North America will be comparatively more sensitive to the short-term changes in commodity prices due to the production profile associated with tight sands oil wells. Accordingly, we expect a reduction in the growth rate for North American tight sands and shale oil. We believe that rail will be the source of transportation most directly impacted by any declines in production due to its comparatively higher cost relative to pipeline transportation. However, current pricing may put short-term pressure on our North Dakota and Mid-Continent assets which source production from tight sand formations.

We do not believe that the decline in crude oil prices will impact our liquids segment meaningfully in the short-term. However, a long-term decline in crude oil prices could have a more significant impact on future production and our rate of growth.

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Expansion Projects

The table and discussion below summarizes our commercially secured projects for the Liquids segment, which have been recently placed into service or will be placed into service in future periods:

Projects

Total Estimated Capital Costs

Expected In-Service Date

Funding

(in millions)

Line 3 Replacement Program(1)

$

2,600

2019

Joint

(2)

Eastern Access Projects:

Line 6B Expansion

320

Complete

Joint

(3)

U.S. Mainline Expansions:

Line 61 (Additional tankage)

380

Complete

Joint

(4)

Line 61 (1,200,000 Bpd capacity)(5)

435

2019

Joint

(4)

Line 3 Replacement Program

In 2014, we and Enbridge jointly announced that shipper support was received to replace portions of the existing 1,031-mile Line 3 pipeline on the Canadian Mainline/Lakehead system between Hardisty, Alberta, Canada and Superior, Wisconsin. Our portion of the Line 3 Replacement Program, referred to as the US L3R Program, includes replacing 358 miles from the U.S./Canadian border at Neche, North Dakota to Superior, Wisconsin. The L3R Program will support the safety and operational reliability of the system, enhance flexibility, allow us and Enbridge to optimize throughput on the mainline system, and will restore approximately 370,000 Bpd capacity from Western Canada into Superior, Wisconsin.

We are in the process of obtaining the appropriate permits for constructing the US L3R Program in Minnesota. The project requires both a Certificate of Need, or Certificate, and an approval of the pipeline’s route, or Route Permit, from the MNPUC. The MNPUC found both the Certificate and Route Permit applications for the US L3R Program through Minnesota to be complete. With respect to the Route Permit, the Minnesota Department of Commerce held public scoping meetings in August 2015.

On February 1, 2016, the MNPUC issued a written order, or the US L3R Order, joining the Line 3 Certificate and Route Permit dockets and requiring the Minnesota Department of Commerce, or DOC, to prepare a final Environmental Impact Statement, or EIS, before the Certificate and Route Permit processes commence, and sent the cases to the Office of Administrative Hearings, or OAH, with direction to restart the process. On February 5, 2016, we filed a Petition for Reconsideration of the requirement to provide a final EIS ahead of the commencement of the Certificate and Route Permit proceedings noted in the US L3R Order. At a hearing held on March 24, 2016 the MNPUC denied the Petition for Reconsideration.

With the issuance of the Environmental Assessment Worksheet, or EAW, on April 11, 2016 the MNPUC commenced the EIS process. Consultation regarding the EAW, which defines the scope of the EIS, commenced with a series of public meetings in communities in Minnesota on April 25, 2016, which concluded on May 13, 2016. The DOC addressed the comments received on the draft EIS scope and issued its scoping recommendations to the MNPUC on September 22, 2016.

Three external parties filed motions requesting that the scoping process be re-opened or that a comment period be established because of the issuance of the Consent Decree settling the Line 6B pipeline crude oil release in Marshall, Michigan and the withdrawal of regulatory applications pending with the MNPUC with respect to the Sandpiper Project discussed above. We filed a reply challenging the need to re-open the scoping process indicating

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that neither of these events warrants further extension of time. The motions filed by the external parties were considered and denied by the MNPUC at a hearing held on October 28, 2016.

At the hearing on October 28, 2016, the MNPUC also approved the scope of the EIS. The MNPUC’s decision was confirmed in a written order on November 30, 2016. The DOC published the EIS Public Notice on December 5, 2016, which provided greater clarity with respect to the timeline for the regulatory approval of the US L3R Program in Minnesota. On December 20, 2016, two intervenors filed petitions for reconsideration of the MNPUC’s November 30, 2016 order. We filed a response on January 3, 2017. The MNPUC denied the petitions at a hearing which took place on February 9, 2017. We are currently evaluating the impact of the MNPUC’s November 30, 2016 order on the cost and in-service date of this project. It is possible, under the schedule approved by the MNPUC, that the in-service date could be delayed, at least until later in 2019.

On January 26, 2017, our Board of Directors approved a joint funding agreement with our General Partner for the U.S L3R Program. Under the terms of the agreement, our General Partner and we will fund 99% and 1% of the capital cost of the U.S. L3R Program, respectively. We have an option to increase our interest up to 40% in the U.S. portion at book value at any time up to four years after the project goes into service. Our General Partner paid us approximately $450 million for its 99% interest in the project, including our share of the construction costs to date and other incremental amounts.

We will recover our costs based on our existing Facilities Surcharge Mechanism, or FSM, with the initial term being 15 years. For purposes of the toll surcharge, the agreement specifies a 30 year recovery of the capital based on a cost-of-service methodology.

Light Oil Market Access Program

We and Enbridge have invested in a Light Oil Market Access Program to expand access to markets for growing volumes of light oil production. This program responds to significant developments with respect to supply of light oil from U.S. north central formations and western Canada, as well as refinery demand for light oil in the U.S. Midwest and eastern Canada. The Light Oil Market Access Program includes several projects that will further expand capacity on our U.S. mainline system, upsize the Eastern Access Projects and provide additional access to U.S. Midwestern refineries.

Eastern Access Projects

The Eastern Access Projects included a series of crude oil pipeline expansion projects providing increased access to refineries in the U.S. Upper Midwest and the Canadian provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States. The majority of the Eastern Access Projects were completed between 2013 and 2015. The remaining project was an expansion project for Line 6B to increase capacity from 500,000 Bpd to 570,000 Bpd and included: pump station modifications at Griffith, Niles and Mendon; additional modifications at the Griffith and Stockbridge terminals; and breakout tankage at Stockbridge. The expansion was placed into service in June 2016 at an approximate cost of $320 million.

We will operate the Eastern Access Projects on a cost-of-service basis. The Eastern Access Projects were funded 75% by our General Partner and 25% by us under the Eastern Access Joint Funding Agreement. On January 26, 2017, we exercised our option under the Eastern Access Joint Funding Agreement to acquire an additional 15% interest in the Eastern Access Projects, at its book value of approximately $360 million, which is now in service.

U.S. Mainline Expansion

The U.S. Mainline Expansion Projects include a series of crude oil pipeline expansion projects for our mainline pipeline system between Neche, North Dakota, and Flanagan, Illinois. These projects include the expansion of our existing 36-inch diameter Alberta Clipper pipeline, or Line 67 and our existing 42-inch diameter Southern Access pipeline, or Line 61, and the construction of Line 78, a twin of the Spearhead North pipeline, or Line 62. The expansion on Line 67 and construction of Line 78 were completed during 2015.

The Line 67 pipeline expansion remains subject to the receipt of an amendment to the current Presidential border crossing permit to allow for operation of the Line 67 pipeline at its currently planned operating capacity of 800,000 Bpd. On February 10, 2017, the United States Department of State, or Department, the agency that is responsible for issuing permits for cross-border pipelines pursuant to a delegation of authority by the President under an Executive Order, issued a Draft Supplemental Environmental Impact Statement, or Draft SEIS, which determined that there were no significant adverse environmental impacts from the planned capacity increase. Upon

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closure of a public comment period on the Draft SEIS, which is currently scheduled for March 27, 2017, the Department will review all received comments and prepare a Final SEIS. The Executive Order also requires that the Department initiate a 90-day inter-agency consultation period to solicit comments from certain other federal agencies on whether the Line 67 expansion will serve the “national interest.” Following issuance of the Final SEIS and completion of the inter-agency consultation process, the Administration will make a decision and issue a Presidential Permit if it finds that doing so is in the national interest. This is expected later in the year and meanwhile, a number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with any delays in obtaining this amendment.

The Line 61 expansion, between Superior, Wisconsin and Flanagan, Illinois requires only the addition of pumping horsepower with no pipeline construction. In 2015, we completed the expansion of pipeline capacity to 950,000 Bpd. The additional tankage which cost approximately $380 million was completed in the third quarter of 2016. The remaining work includes an expansion phase to increase the pipeline capacity to 1,200,000 Bpd at an expected cost of approximately $435 million. In conjunction with shippers, a decision was made to delay the in-service date of this remaining expansion phase to 2019 to align more closely with the anticipated in-service date for the US L3R Program.

We will operate the U.S. Mainline Expansions projects on a cost-of-service basis. These projects are jointly funded 75% by our General Partner and 25% by us under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement. We have the option to increase our economic interest held up to 15% at cost.

Natural Gas

Our Natural Gas segment includes the operations of our Anadarko, East Texas, North Texas, and Texas Express NGL systems, as well as our marketing operations. For a detailed description of each of these systems, refer to Part I, Item I. Business. The following tables set forth the operating results of our Natural Gas segment and the approximate average daily volumes of natural gas throughput and NGLs produced on our major systems for the years ended December 31, 2016, 2015 and 2014.

		December 31,
		2016				2015				2014
		(in millions)
Operating results:
Operating revenues		$	1,966.0			$	2,842.7			$	5,894.3
Commodity costs			1,659.1				2,372.9				5,145.9
Segment gross margin			306.9				469.8				748.4
Operating expenses:
Operating and administrative			290.9				351.0				423.0
Depreciation and amortization			154.4				157.8				151.4
Asset impairment			10.6				12.3				15.6
Goodwill impairment			—				246.7				—
Operating expenses			455.9				767.8				590.0
Operating income (loss)			(149.0	)			(298.0	)			158.4
Other income			30.0				29.3				13.2
Net income (loss)		$	(119.0	)		$	(268.7	)		$	171.6
Operating Statistics (MMBtu/d):
East Texas			904,000				964,000				1,030,000
Anadarko			616,000				773,000				827,000
North Texas			197,000				265,000				293,000
Total			1,717,000				2,002,000				2,150,000
NGL Production (Bpd)			68,843				81,632				83,675

Year ended December 31, 2016, compared with year ended December 31, 2015

The operating loss of our natural gas business for the year ended December 31, 2016, decreased $149.0 million, as compared with the year ended December 31, 2015, primarily as a result of a reduction in

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goodwill impairment charge. During the year ended December 31, 2015, the Natural Gas segment recognized a goodwill impairment charge of $246.7 million. No such impairment charge was recognized during 2016. The effects of the reduction in impairment charges were offset by lower segment gross margin in the 2016 period, as discussed below.

Decreases in “Operating revenues” and “Commodity costs” for the year ended December 31, 2016, as compared to the same period in 2015, are primarily due to decreases in commodity prices and the resulting decrease in volumes from reduced drilling activities.

Segment gross margin decreased $162.9 million for the year ended December 31, 2016, as compared to the same period in 2015, in part due to increased non-cash, mark-to-market losses due to derivative transactions. Non-cash, mark-to-market losses increased $53.8 million for the year ended December 31, 2016, as compared to the same period in 2015. This increase in non-cash, mark-to-market losses is primarily related to the increased commodity prices of condensate and NGLs period over period, partially offset by the gains from the reversal of previously recognized unrealized mark-to-market losses as the underlying transactions were settled.

Segment gross margin decreased by approximately $41.8 million for the year ended December 31, 2016, as compared to the same period in 2015, due to reduced natural gas throughput. The average daily volumes of our major systems for the year ended December 31, 2016 decreased by approximately 285,000 million British thermal units per day, or MMBtu/d, or 14%, as compared to the same period in 2015. The average NGL production for the year ended December 31, 2016, decreased 12,789 Bpd, or 16%, as compared to the same period in 2015. The decreases in volumes were primarily attributable to the continued low commodity price environment for natural gas, condensate and NGLs, which resulted in reductions in drilling activity by producers in the areas we operate.

Segment gross margin decreased $34.0 million for the year ended December 31, 2016, as compared to the same period in 2015, due to a decrease in storage margins as a result of lower system volumes and the sale of liquids product inventory at lower prevailing market prices relative to the cost of product inventory.

Segment gross margin also decreased $16.9 million for the year ended December 31, 2016, as compared to the same period in 2015, due to a decrease in processing margins primarily driven by lower commodity prices along with decline in NGL volumes and associated keep whole volumes in the Anadarko and East Texas regions.

Operating and administrative costs decreased $60.1 million for the year ended December 31, 2016, as compared to the same period in 2015, primarily due to workforce reductions and other cost savings related to the sale of certain trucks, trailers and related facilities during the third quarter of 2016. Operating and administrative costs also decreased due to gains of $5.6 million recorded during the first quarter of 2016 to recognize return of escrow funds and a reversal of a contingent liability related to an acquisition. For further details regarding these amounts, refer to Item 1. Financial Statements, Note 7. Acquisitions.

Year ended December 31, 2015, compared with year ended December 31, 2014

The operating income of our natural gas business for the year ended December 31, 2015, decreased $456.4 million, as compared with the year ended December 31, 2014, in part due to a $246.7 million goodwill impairment charge, as discussed above.

Decreases in “Operating revenues” and “Commodity costs” for the year ended December 31, 2015, as compared with the same period in 2014, are primarily due to decreases in commodity prices and the resulting decreased volumes from lower drilling activities. Segment gross margin decreased $278.6 for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to the following reasons:

Segment gross margin experienced a net decrease of $216.8 million, due to non-cash, mark-to-market losses of $58.3 million for the year ended December 31, 2015, including $1.6 million of gains associated with the assignments of certain natural gas contracts, as compared to gains of $158.5 million for year ended December 31, 2014. The decrease is primarily the result of a reclassification of previously recognized unrealized mark-to-market net gains where the underlying transactions were settled, coupled with decreased non-cash, mark-to-market net gains due to smaller decreases in average forward prices during 2015 than in 2014.

Segment gross margin decreased $28.0 million for the year ended December 31, 2015, as compared with the same period in December 31, 2014, due to decreased margins from lower commodity prices, net of hedges, related to contracts where we were paid in commodities for our services.

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Our segment gross margin was also impacted by decreased margins within our marketing function due to natural gas pricing differentials between market centers by approximately $9.7 million for the year ended December 31, 2015, as compared to the year ended December 31, 2014. During the first quarter of 2014, we benefited from the difference between market centers in the Mid-Continent supply areas and market area in the Midwest which arose due to higher than usual demand from winter weather conditions in the Midwest.

Segment gross margin was affected by reduced production volumes which negatively affected segment gross margin by approximately $28.7 million for the year ended December 31, 2015, as compared to the year ended December 31, 2014. The average daily volumes of our major systems for the year ended December 31, 2015, decreased by approximately 148,000 million British thermal units per day, or MMBtu/d, or 7% when compared to the year ended December 31, 2014. The average NGL production for the year ended December 31, 2015, decreased by 2,043 Bpd, or 2%, when compared to the year ended December 31, 2014. The decrease in natural gas and NGL volumes was primarily attributable to the continued low commodity price environment for natural gas, NGLs and condensate, which has resulted in reductions in drilling activity from producers in the areas we operate.

Our segment gross margin also decreased $9.3 million for the year ended December 31, 2015, as compared with the same period in December 31, 2014. On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Natural Gas segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third party. We recognized a loss of $9.3 million in connection with this transaction, primarily related to costs to transfer certain fixed-demand storage and transportation obligations to the buyer.

Our segment gross margin decreased $8.0 million for the year ended December 31, 2015, as compared with the same period in 2014, due to lower storage margins as a result of the relative difference between the injection price paid to purchase and store natural gas, crude oil and NGLs and the withdrawal price at which these commodities are sold from storage.

Segment gross margin increased $7.4 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to decreased physical measurement losses as a result of system efficiencies. Physical measurement gains and losses routinely occur on our systems as part of our normal operations, which result from evaporation, shrinkage, differences in measurement between receipt and delivery locations and other operational conditions

Our segment gross margin also increased $5.6 million for year ended December 31, 2015, when compared to the same period of 2014, for decreases in non-cash charges to decrease the cost basis of our natural gas inventory to net realizable value recorded in 2014.

Operating and administrative costs decreased $72.0 million for the year ended December 31, 2015, when compared to the year ended December 31, 2014 primarily due to cost reduction efforts undertaken by management, including $15.0 million in workforce reductions, which resulted in a decrease in contract labor as well as other related cost benefits. In addition, other cost reduction efforts have resulted in reduced repairs and maintenance costs.

Depreciation and amortization expense increased $6.4 million, for the year ended December 31, 2015, compared with the year ended December 31, 2014, due to additional assets that were placed into service.

Other income increased $16.1 million for the year ended December 31, 2015, compared with the year ended December 31, 2014, primarily due to increases in equity earnings on our investment in the Texas Express NGL system. These increases were a result of higher volumes and increases in ship-or-pay commitments during 2015.

Future Prospects Update for Natural Gas

Demand for our midstream services primarily depends upon the supply of natural gas and associated natural gas from crude oil development and the drilling rate for new wells. Demand for these services depends on overall economic conditions and commodity prices. Commodity prices for natural gas, NGLs, condensate, and crude oil continue to remain low. The depressed commodity price environment is the most significant factor for reduced drilling activity and low volumes in the basins in which we operate. Due to the extended low commodity price environment, we expect drilling activity to remain low and as a result, we expect to see declining volumes on our systems in 2017.

We have a hedging program in place to assist in mitigating our direct commodity risk from contracts in which we are paid in commodities for our services. However, we are not fully hedged, and our hedge positions for 2017 are significantly lower than they were in 2016. We have hedged approximately 70% and 5% of our direct forecasted

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commodity cash flow exposure for 2017 and 2018, respectively. Our condensate and NGL hedge prices for 2017 are approximately 20% and on average 30% lower than 2016, respectively. See Liquidity and Capital Resources — Derivative Activities below. Despite our hedging program, we still bear indirect commodity price exposure as lower drilling activity impacts the volumes on our systems as well as direct commodity price exposure for unhedged commodity positions. We expect this indirect impact on our volumes to fluctuate depending on future price movements. In addition, we also expect our average NGL transportation commitments on the Texas Express system to increase from 29,000 Bpd in 2016 to 75,000 Bpd in 2017.

In light of the extended low commodity price environment, we have been evaluating opportunities to strengthen our natural gas business. As part of this evaluation, we are exploring strategic alternatives for our investments in each of Midcoast Operating and MEP. We have been working with MEP to explore and evaluate a broad range of strategic alternatives to address these challenges within our Natural Gas business. These additional various strategic alternatives may include, but are not necessarily limited to: asset sales; mergers, joint ventures, reorganizations or recapitalizations; and further reductions in operating and capital expenditures for the Natural Gas business. The evaluation process is ongoing, and no decision on any particular strategic alternative has been reached.

On January 26, 2017, MEP entered into a definitive merger agreement, referred to as the Merger Agreement, with our General Partner whereby our General Partner will acquire, for cash, all of the outstanding publicly held common units of MEP at a price of $8 per common unit for an aggregate transaction value of $170.2 million. The public interest to be acquired by our General Partner represents an approximate 25% effective interest in our natural gas gathering and processing business. This action enables us to retain more of our cash flow, reduces our costs associated with an additional public company and simplifies our corporate structure. In connection with the execution of the Merger Agreement, we have entered into a support agreement with MEP and our General Partner whereby we agreed, in our capacity as a holder of MEP units, to vote our units in favor of the merger agreement and the transactions contemplated by the merger agreement.

Enbridge has indicated that as part of the integration resulting from the Spectra merger, its U.S. sponsored vehicles, which includes MEP, will be reviewed in context of the combined enterprise. In addition, as discussed more fully above with respect to future prospects for the liquids segment, the interim operating covenants that Enbridge agreed to as part of its merger agreement with Spectra Energy Corp. are also applicable to MEP and its subsidiaries. Thus, while we continue to progress our strategic evaluation of MEP, it is possible that the evaluation and potential execution of any such strategy could be affected by that merger and extend into the second quarter of 2017.

Other

Other consists of interest expense, allowance for equity used during construction and other costs such as income taxes, which are not allocated to the business segments.

		December 31,
		2016				2015				2014
		(in millions)
Operating Results:
Operating and administrative expenses		$	13.7			$	14.4			$	10.6
Operating loss			(13.7	)			(14.4	)			(10.6	)
Interest expense, net			(445.5	)			(322.0	)			(403.2	)
Allowance for equity used during construction			45.5				70.3				57.2
Other income (expense)			1.5				—				(4.3	)
Loss before income tax expense			(412.2	)			(266.1	)			(360.9	)
Income tax expense			(0.9	)			(4.9	)			(9.6	)
Net loss		$	(413.1	)		$	(271.0	)		$	(370.5	)

Year ended December 31, 2016 compared with year ended December 31, 2015

The $142.1 million increase in our segment net loss for the year ended December 31, 2016, as compared to the same period in 2015, was mainly attributable to an increase in interest expense of $123.5 million, year over year. The increase is due to an increase in our average outstanding debt balance during the year ended December 31, 2016, which includes $1.6 billion of senior unsecured notes that were issued in October 2015. In addition, interest expense from ineffectiveness on hedging instruments increased $105.4 million, as compared to the same period in 2015.

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Further, allowance for equity used during construction, or AEDC, decreased $24.8 million for the year ended December 31, 2016, when compared to the same period in 2015, as a result of a reduction in outstanding capital projects in which AEDC is being recognized.

Year ended December 31, 2015 compared with year ended December 31, 2014

The $99.5 million decrease in our net loss for the year ended December 31, 2015, as compared to the same period in 2014 was primarily attributable to a decrease in interest expense.

Interest expense decreased $81.2 million for the year ended December 31, 2015, when compared with the year ended December 31, 2014, primarily due to a decrease in the recognition of the ineffective portion of unrealized and realized losses on our pre-issuance hedges. In 2014, we recognized $100.6 million in interest expense for hedge ineffectiveness from extending the maturity dates of our pre-issuance hedges that were set to mature in 2014. In October 2015, we settled some of these pre-issuance hedges. This decrease period over period was offset by higher interest cost on newly-issued senior debt.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary operating cash requirements consist of normal operating expenses, maintenance capital expenditures, funding requirements associated with environmental costs, distributions to our partners and payments associated with our risk management activities. We expect to fund our current and future short-term cash requirements for these items from our operating cash flows supplemented as necessary by issuances of commercial paper and borrowings under our Credit Facilities. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our Credit Facilities.

Our current business strategy includes developing and expanding our existing business through organic growth and targeted acquisitions, in addition to the strategies, and subject to the short-term limitations, discussed above under Strategic Review.

We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as retire our maturing and callable debt, first from operating cash flows and then from issuances of commercial paper and borrowings on our Credit Facilities. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities, although there can be no assurance that such financings will be available on favorable terms, if at all.

In the past, when we had attractive growth opportunities in excess of our own capital raising capabilities, our General Partner provided supplementary funding, or participated directly in projects, to enable us to undertake such opportunities. If in the future we have attractive growth opportunities that exceed capital raising capabilities, we could seek similar arrangements from our General Partner, but there can be no assurance that this funding can be obtained.

Available Liquidity

Our primary source of short-term liquidity is provided by our $1.5 billion commercial paper program, which is supported by our $2.0 billion multi-year unsecured revolving credit facility, which we refer to as the Credit Facility, and our $625.0 million credit agreement, which we refer to as the 364-Day Credit Facility. We refer to the 364-Day Credit Facility and the Credit Facility as our Credit Facilities. We access our commercial paper program primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities. At December 31, 2016, we had approximately $846.3 in available credit under the terms of our Credit Facilities. For a description of our commercial paper program and our Credit Facilities, refer to Item 8. Financial Statements and Supplementary Data, Note 17. Debt.

In addition, on July 26, 2016, we entered into an unsecured revolving 364-day credit agreement with Enbridge (U.S.) Inc., or EUS, an affiliate of Enbridge and the owner of our General Partner, which we refer to as the EUS 364-Credit Facility. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $750.0 million. For further details, refer to Item 8. Financial Statements and Supplementary Data, Note 24. Related Party Transactions.

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As of December 31, 2016, although we had a working capital deficit of approximately $0.5 billion, we had approximately $1.2 billion of consolidated liquidity to meet our ongoing operational, investing and financing needs as described above, as well as the funding requirements associated with the environmental remediation costs resulting from the crude oil release on Line 6B.

The following table, sets forth the consolidated liquidity available to us at December 31, 2016.

		EEP				MEP				Total
		(in millions)
Cash and cash equivalents		$	101.4			$	7.4			$	108.8
Total commitments under EEP’s Credit Facilities			2,625.0				—				2,625.0
Total commitments under the EUS 364-day Credit Facility			750.0				—				750.0
Total commitments under MEP’s Credit Agreement			—				670.0				670.0
Less: Amounts outstanding under EEP’s Credit Facilities			1,265.1				—				1,265.1
Amounts outstanding under MEP’s Credit Agreement			—				420.0				420.0
Principal amount of commercial paper outstanding			392.5				—				392.5
Amounts outstanding under the EUS 364-day Credit Facility			750.0				—				750.0
Letters of credit outstanding			121.1				—				121.1
Total		$	947.7			$	257.4			$	1,205.1

Capital Resources

Debt and Equity Securities

Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private equity and credit markets to obtain the capital necessary to fund these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our internal growth projects and targeted acquisitions will require additional permanent capital and require us to bear the cost of constructing and acquiring assets before we begin to realize a return on them. From time to time, if the capital markets are constrained, our ability and willingness to complete future debt and equity offerings may be limited, which in turn, could affect our ability to execute our growth strategy or complete our planned construction projects. The timing of any future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

Subject to the foregoing, from time to time, we may seek to satisfy liquidity needs through the issuance of registered debt or equity securities. We have a current shelf registration statement on Form S-3 that allows us to issue an unlimited amount of equity and debt securities in underwritten public offerings.

Credit Facilities

The Credit Facility, permits aggregate borrowings of up to, at any one time outstanding, $2.0 billion, a letter of credit subfacility and a swing line subfacility. On July 28, 2016, we amended the Credit Facility to increase the lending commitments by $25.0 million. The Credit Facility matures September 26, 2020; however, $175.0 million of commitments will expire on the original maturity date of September 26, 2018.

The 364-Day Credit Facility, permits aggregate borrowings of up to $625.0 million: (1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion, and (2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. The current revolving credit termination date is June 30, 2017.

At December 31, 2016, the Credit Facilities provide an aggregate amount of approximately $2.6 billion of bank credit, which we use to fund our general activities and working capital needs. The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding.

In addition, the EUS 364-day Credit Facility permits aggregate borrowing of up to, at any one time outstanding, $750.0 million. The EUS 364-day Credit Facility is discussed in Note 24. Related Party Transactions.

As of December 31, 2016, we were in compliance with the terms of all of our financial covenants under the Credit Facilities. For further details regarding the Credit Facilities and the amendments thereto, refer to Item 8. Financial Statements and Supplementary Data, Note 17. Debt.

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Commercial Paper

Our commercial paper program provides for the issuance of up to an aggregate principal amount $1.5 billion of commercial paper and is supported by our Credit Facilities. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our Credit Facilities. Our policy is that the commercial paper we can issue is limited by the amounts available under our Credit Facility up to an aggregate principal amount of $1.5 billion, as mentioned above. Our policy is also to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at any time.

Senior Notes

On October 6, 2015, we closed a public offering of $1.6 billion of senior unsecured notes, comprised of $500 million aggregate principal amount of notes due October 15, 2020, $500 million aggregate principal amount of notes due October 15, 2025 and $600 million aggregate principal amount of notes due October 15, 2045 for net proceeds of approximately $1.575 billion after deducting underwriting discounts and commissions and estimated offering expenses. For further details regarding the senior notes, refer to Item 8. Financial Statements and Supplementary Data, Note 17. Debt.

Our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $200.0 million of senior notes issued by the OLP, which we refer to as the OLP Notes. The OLP Notes represent unsecured obligations that are structurally senior to our senior notes. All of the OLP Notes pay interest semi-annually. For further details regarding the OLP Notes, refer to Item 8. Financial Statements and Supplementary Data, Note 17. Debt.

Junior Subordinated Notes

The $400.0 million in principal amount of our fixed/floating rate, junior subordinated notes due October 1, 2067, which we refer to as the Junior Notes, represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness. The Junior Notes bear interest at a fixed annual rate of 8.05%, exclusive of any discounts or interest rate hedging activities, payable semi-annually in arrears on April 1 and October 1 of each year until October 1, 2017. After October 1, 2017, the Junior Notes will bear interest at a variable rate equal to the three-month London Interbank Offered Rate, or LIBOR, for the related interest period increased by 3.7975%, payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2018. For further details regarding the junior subordinated notes, refer to Item 8. Financial Statements and Supplementary Data, Note 17. Debt.

Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit issuances for the year ended December 31, 2015. The proceeds from the March 2015 offering were used to fund a portion of our capital expansion projects and for general partnership purposes. There were no issuances of Class A common units for the years ended December 31, 2016 or 2014.

2015 Issuance Date		Number of Class A common units Issued				Offering Price per Class A common unit				Net Proceeds to the Partnership(1)				General Partner Contribution(2)				Net Proceeds Including General Partner Contribution
		(in millions, except units and per unit amounts)
March			8,000,000			$	36.70			$	288.8			$	6.0			$	294.8

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Series 1 Preferred Units

In 2013, we issued and sold 48,000,000 Series 1 preferred units, representing limited partner interests in us, or Preferred Units, for aggregate proceeds of approximately $1.2 billion. We used proceeds from the Preferred Unit issuance to repay commercial paper, to finance a portion of our capital expansion program relating to our core liquids and natural gas systems and for general partnership purposes. On July 30, 2015, we amended our limited partnership agreement to extend the deferral of distribution payments, to extend the rate reset pricing date, and to defer the conversion option date, as discussed below.

The Preferred Units are entitled to annual cash distributions of 7.50% of the issue price, payable quarterly, which are subject to reset on June 30, 2020, and each subsequent five-year anniversary thereafter. However, these quarterly cash distributions, during the first full twenty quarters ending June 30, 2018, will accrue and accumulate, which we refer to as the Payment Deferral. These amounts will be paid in equal amounts over a twelve-quarter period beginning in the first quarter of 2019.

On or after June 1, 2018, at the sole option of the holder of the Preferred Units, the Preferred Units may be converted into Class A Common Units, in whole or in part, at a conversion price of $27.78 per unit plus any accrued, accumulated and unpaid distributions, excluding the Payment Deferral, as adjusted for splits, combinations and unit distributions. For further details regarding the Preferred Units, refer to Item 8. Financial Statements and Supplementary Data, Note 20. Partners’ Capital.

Midcoast Energy Partners, L.P.

At December 31, 2016, we owned 5.9% of outstanding MEP Class A common units, 100% of the outstanding MEP Subordinated Units, 100% of MEP’s general partner and 48.4% of the limited partner interests in Midcoast Operating. On February 15, 2017, the subordination period ended. On that date, the outstanding subordinated units converted into a new class of common units, which we refer to as Class B common units. Further, on January 26, 2017, MEP entered into the Merger Agreement with our General Partner whereby our General Partner will acquire for cash, subject to the terms and conditions thereof, all of the outstanding publicly held common units of MEP at a price of $8 per common unit for an aggregate transaction value of $170.2 million. The public interest to be acquired by our General Partner represents an approximate 25% effective interest in our natural gas gathering and processing business. In connection with the execution of the Merger Agreement, we have entered into a support agreement with MEP and our General Partner whereby we agreed, in our capacity as a holder of MEP units, to vote our units in favor of the merger agreement and the transactions contemplated by the merger agreement.

MEP Credit Agreement

MEP, Midcoast Operating, and their domestic material subsidiaries are party to a senior revolving credit facility, which we refer to as the MEP Credit Agreement, which permits aggregate borrowings of up to $670.0 million, at any one time outstanding. The original term of the MEP Credit Agreement was three years with an initial maturity date of November 13, 2016, subject to four one-year requests for extensions at the lenders’ discretion, two of which we have utilized. The MEP Credit Agreement’s current maturity date is September 30, 2018; however, $25.0 million of commitments expire on September 30, 2017.

The MEP Credit Agreement also requires compliance with two financial covenants. MEP must not permit the ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio) of MEP and its consolidated subsidiaries (including Midcoast Operating), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. MEP also must maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.

Each of MEP’s domestic material subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the borrowers arising under the MEP Credit Agreement and other loan documents, and each co-borrower has guaranteed all such indebtedness and liabilities of the other co-borrower. The MEP Credit Agreement is unsecured but security will be provided upon occurrence of any of the following: (1) for two consecutive quarters, the total leverage ratio as described below, exceeds 4.25 to 1.00, or 4.75 to 1.00 during acquisition periods, (2) uncured breach to certain terms and conditions of the MEP Credit Agreement and (3) obtaining a non-investment grade initial debt rating from either S&P or Moody’s.

At December 31, 2016, MEP was in compliance with the terms of their financial covenants in the MEP Credit Agreement. Due to the extended low commodity price environment and the potential implications on MEP’s results of operations, it is likely that MEP may not be able to meet the total leverage ratio financial covenant at some point

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during 2017 without further action on its part. If this were to occur, we have indicated to MEP that we expect to provide them certain additional capital contributions to prevent a default under the MEP Credit Agreement. MEP would also seek a waiver from its lenders, pursue refinancing of the amounts outstanding under the MEP Credit Agreement, or seek to take other action to prevent a default under the MEP Credit Agreement, although there can be no assurance that MEP will secure any such preventative actions. Failure to comply with one or both of the financial covenants may result in the occurrence of an event of default under the MEP Credit Agreement, which would result in a cross-default under the note purchase agreement relating to MEP’s senior notes. If an event of default were to occur, the lenders could, among other things, terminate their commitments under the MEP Credit Agreement, demand immediate payment of all amounts borrowed by MEP and Midcoast Operating, trigger the springing liens, and require adequate security or collateral for all outstanding letters of credit outstanding under the facility. In addition, MEP and Midcoast Operating are restricted under the MEP Credit Agreement from making distributions to us in certain circumstances involving certain defaults under that agreement or any event of default under that agreement. Furthermore, a default under the MEP Credit Agreement or Purchase Agreement would limit our ability to receive payment of amounts that may be owed to us under the Financial Support Agreement. Any inability of MEP or Midcoast Operating to make distributions, or of Midcoast Operating to repay its indebtedness to us, could reduce our cash flows and affect our results of operations. See Item 1A. Risk Factors — Risks Related to Our Business. In addition, as discussed above under Future Prospects for Natural Gas, as part of an evaluation of opportunities to strengthen our natural gas business in light of the low commodity price environment, MEP entered into the Merger Agreement with our General Partner whereby our General Partner will acquire, for cash, all of the outstanding publicly held common units of MEP.

MEP Senior Notes

MEP has $400.0 million of notes consisting of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. MEP pays interest on the Notes semi-annually on March 31 and September 30, and commenced on March 31, 2015.

The Notes were issued pursuant to a Note Purchase Agreement, or the Purchase Agreement, between MEP and the purchasers named therein. The Notes and all other obligations under the Purchase Agreement are unconditionally guaranteed by each of MEP’s domestic material subsidiaries pursuant to a guaranty agreement. Until such time as MEP obtain an investment grade rating from either Moody’s or S&P and upon certain trigger events, MEP and the guarantors will grant liens in their assets (subject to certain excluded assets) to secure the obligations under the Notes. There are currently no liens associated with the Notes.

The Purchase Agreement also requires compliance with two financial covenants. MEP must not permit the ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. MEP also must maintain, on a consolidated basis, as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four quarter period then ended of at least 2.50 to 1.00.

At December 31, 2016, MEP was in compliance with the terms of their financial covenants under the Notes and the related purchase agreement. Due to the extended low commodity price environment and the potential implications on MEP’s results of operations, it is likely that MEP may not be able to meet the total leverage ratio financial covenant at some point during 2017 without further action on its part. If this were to occur, we have indicated to MEP that we expect to provide them certain additional capital contributions to prevent a default under the MEP Credit Agreement. MEP would also seek a waiver from the note holders, pursue refinancing of the amounts outstanding under the Notes or seek to take other action to prevent a default under the Purchase Agreement and the Notes, although there can be no assurance that MEP will secure any such preventative actions. Any failure to comply with one or both of the financial covenants could result in an event of default under the Purchase Agreement and the Notes and result in a cross-default under the MEP Credit Agreement. If an event of default were to occur, the note holders could, among other things, demand immediate payment of the Notes and trigger the springing liens. In addition, as discussed above, MEP and Midcoast Operating are restricted from making distributions to us in certain circumstances involving certain defaults under that agreement or any event of default under that agreement. Furthermore, a default under the MEP Credit Agreement or Purchase Agreement would limit our ability to receive payment of amounts that may be owed to us under the Financial Support Agreement. Any inability of MEP or Midcoast Operating to make distributions, or of Midcoast Operating to repay its indebtedness to us, could reduce our cash flows and affect our results of operations.

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Joint Funding Arrangements

In order to obtain capital, we have explored, and may continue to explore, numerous options, including joint funding arrangements.

Amendment of OLP Limited Partnership Agreement

On July 30, 2015, the partners amended and restated the limited partnership agreement of the OLP, pursuant to which our General Partner did not receive Series EA and ME, collectively, the Series, distributions commencing in the quarter ended June 30, 2015 through the quarter ended March 31, 2016. The General Partner’s capital funding contribution requirements for each of those two Series, commencing in August 2015, were reduced by the amount of its foregone cash distributions from the respective Series, until the date aggregate reductions in capital contributions for such Series equaled the foregone cash distributions for such Series. As of December 31, 2016, capital contributions offset foregone cash distributions.

Joint Funding Arrangement for Line 3 Replacement Program

On January 26, 2017, our Board of Directors approved a joint funding agreement with our General Partner for the U.S L3R Program. Under the terms of the agreement, our General Partner will fund 99% and we will fund 1% of the capital cost of the U.S. L3R Program, with an option for us to increase our interest up to 40% in the U.S. portion at book value at any time up to four years after the project goes into service. Our General Partner paid us approximately $450 million for its 99% interest in the project, including our share of the construction costs to date.

Joint Funding Arrangement for Eastern Access Projects

The OLP has a series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance the Eastern Access Projects to increase access to refineries in the U.S. Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States. As of December 31, 2016, our General Partner owned 75% of the EA interests, and, except as described above in Amendment of OLP Limited Partnership Agreement, the projects are jointly funded by our General Partner at 75% and us at 25%. On January 26, 2017, we exercised our option under the Eastern Access Joint Funding Agreement to acquire an additional 15% interest in the Eastern Access Projects, which is now in service, at its book value of approximately $360 million as discussed above.

Our General Partner made equity contributions totaling $13.8 million and $119.3 million to the OLP for the years ended December 31, 2016 and 2015, respectively, to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Joint Funding Arrangement for U.S. Mainline Expansion

The OLP also has a series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance the Mainline Expansion Projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead System between Neche, North Dakota and Superior, Wisconsin. Our General Partner owns 75% of the ME interests, and, except as described above in Amendment of OLP Limited Partnership Agreement, the projects are jointly funded by our General Partner at 75% and us at 25%, under the Mainline Expansion Joint Funding Agreement, which is similar to the Eastern Access Joint Funding Agreement.

Our General Partner has made equity contributions totaling $90.0 million and $673.3 million to the OLP for the years ended December 31, 2016 and 2015, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.

All other operations are captured by the Lakehead interests. For further details regarding our joint funding arrangements refer to Item 8. Financial Statements and Supplementary Data, Note 24. Related Party Transactions.

Sale of Accounts Receivable

We and certain of our subsidiaries are parties to a receivables purchase agreement, which we refer to as the Receivables Agreement, with an indirect, wholly-owned subsidiary of Enbridge. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of certain of our subsidiaries and certain subsidiaries of MEP that are participating sellers under the Receivables Agreement, up to an aggregate monthly maximum of $450.0 million, net of receivables that have not been collected. The Receivables Agreement was amended in June 2016 to extend the termination date of the agreement to December 31, 2019.

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For further details regarding the Receivable Agreement, refer to Item 8. Financial Statements and Supplementary Data, under Note 24. Related Party Transactions.

Cash Requirements

Capital Spending

We categorize our capital expenditures as either maintenance capital or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which are worn, obsolete or completing its useful life. We also include in maintenance capital expenditures a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital will increase due to the growth of our pipeline systems and the aging of portions of these systems. Maintenance capital expenditures are expected to be funded by operating cash flows.

Expansion capital expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards. We anticipate funding expansion capital expenditures temporarily through borrowing under the terms of the Credit Agreement, with permanent debt and equity funding being obtained when appropriate.

We maintain a comprehensive integrity management program for our pipeline systems, which relies on the latest technologies that include internal pipeline inspection tools. These internal pipeline inspection tools identify internal and external corrosion, dents, cracking, stress corrosion cracking and combinations of these conditions. We regularly assess the integrity of our pipelines utilizing the latest generations of metal loss, caliper and crack detection internal pipeline inspection tools. We also conduct hydrostatic testing to determine the integrity of our pipeline systems. Accordingly, we incur substantial expenditures each year for our integrity management programs. We expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Under our capitalization policy, expenditures that replace major components of property or extend the useful lives of existing assets are capital in nature, while expenditures to inspect and test our pipelines are usually considered operating expenses.

We incurred capital expenditures of $852.6 million for the year ended December 31, 2016, including $69.5 million of maintenance capital expenditures. Of those capital expenditures, $117.3 million was financed by contributions from our General Partner and MPC via joint funding arrangements. At December 31, 2016, we had approximately $348.8 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment in the future.

Acquisitions

We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing them. We expect to obtain the funds needed to make acquisitions through a combination of cash flows from operating activities, borrowings under our Credit Facilities, joint funding arrangements and the issuance of additional debt and equity securities. All acquisitions are considered in the context of the practical financing constraints presented by the capital markets.

As discussed above, on February 15, 2017, through our joint venture with MPC we acquired a minority stake in the Bakken Pipeline System. We funded the $1.5 billion acquisition through a bridge loan provided by an affiliate of our General Partner. For further details regarding our funding arrangements refer to Future Prospects Update for Liquids — Bakken Pipeline System.

Forecasted Expenditures

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. The following table sets forth our estimated maintenance and expansion capital expenditures, net of joint funding, of $410 million for the year ending December 31, 2017. We expect to receive funding of approximately $420 million from our General Partner based on our joint funding arrangements for the U.S. L3R Program, Eastern Access Projects and Mainline Expansion Projects. Although we anticipate making these expenditures in 2017, these estimates may change due to factors beyond our control, including weather-related issues, construction timing,

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regulatory permitting, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets.

		Total Forecasted Expenditures(1)
		(in millions)
Liquids Projects
Eastern Access Projects		$	25
U.S. Mainline Expansions			70
Line 3 Replacement			355
Liquids Integrity Program			80
Expansion Capital			190
Maintenance Capital Expenditures			75
			795
Less joint funding from:
General Partner			420
Liquids Total		$	375
Natural Gas Projects
Expansion Capital		$	35
Maintenance Capital Expenditure			40
			75
Less joint funding from:
MEP			40
Natural Gas Total		$	35
TOTAL		$	410

Distributions

We make quarterly distributions to our General Partner and the holders of our limited partner interests in an amount equal to our “available cash.” As defined in our partnership agreement, “available cash” represents for any calendar quarter, the sum of all of our cash receipts plus reductions in cash reserves established in prior quarters less cash disbursements and additions to cash reserves in that calendar quarter. We establish reserves to provide for the proper conduct of our business, to stabilize distributions to our unitholders and the General Partner and, as necessary, to comply with the terms of any of our agreements or obligations. Enbridge Management, as the delegate of our General Partner under the delegation of control agreement, computes the amount of our “available cash.”

Enbridge Management, as the owner of our i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution to our limited partners and General Partner, the number of i-units owned by Enbridge Management and the percentage of our total units owned by Enbridge Management will increase automatically under the provisions of our partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management’s listed and voting shares that are then outstanding. The amount of this increase in i-units is determined by dividing the cash amount distributed per common unit by the average price of one of Enbridge Management’s listed shares on the NYSE for the 10 trading day period immediately preceding the ex-dividend date for Enbridge Management’s shares multiplied by the number of shares outstanding on the record date. The cash equivalent amount of the additional i-units is treated as if it had actually been distributed for purposes of determining the distributions to be made to our General Partner.

For purposes of calculating the sum of all distributions of available cash, the cash equivalent amount of the additional i-units that are issued when a distribution of cash is made to our General Partner and limited partner interests is treated as a distribution of available cash. As set forth in our partnership agreement, we will not make cash distributions on our i-units, but instead will distribute additional i-units such that cash is retained and used in

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our operations and to finance a portion of our capital expansion projects. During 2016, we distributed a total of 8,571,429 i-units through quarterly distributions to Enbridge Management, compared with 4,980,552 and 4,562,088 in 2015 and 2014, respectively.

The following table represents cash we have retained in our business since January 2014 from the in-kind distribution of additional i-units:

Distribution Payment Date		Amount Retained for Distribution to i-units Holders				Retained from General Partner				Total Cash Retained
		(in millions)
2016
November 14		$	46.6			$	1.0			$	47.6
August 12			45.5				0.9				46.4
May 13			44.3				0.9				45.2
February 12			42.7				0.9				43.6
		$	179.1			$	3.7			$	182.8
2015
November 13		$	41.8			$	0.9			$	42.7
August 14			41.0				0.8				41.8
May 15			39.5				0.8				40.3
February 13			38.9				0.8				39.7
		$	161.2			$	3.3			$	164.5
2014
November 14		$	37.3			$	0.8			$	38.1
August 14			36.7				0.8				37.5
May 15			35.3				0.7				36.0
February 14			34.6				0.7				35.3
		$	143.9			$	3.0			$	146.9