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, 2015
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. o

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, 2015, was $7,186,696,792.

As of February 12, 2016 the registrant has 262,208,428 Class A common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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TABLE OF CONTENTS

		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			27
Item 2. Properties			46
Item 3. Legal Proceedings			46
Item 4. Mine Safety Disclosures			46
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of   Equity Securities			47
Item 6. Selected Financial Data			48
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			51
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			87
Item 8. Financial Statements and Supplementary Data			91
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			165
Item 9A. Controls and Procedures			165
Item 9B. Other Information			166
PART III
Item 10. Directors, Executive Officers and Corporate Governance			167
Item 11. Executive Compensation			173
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder   Matters			193
Item 13. Certain Relationships and Related Transactions, and Director Independence			194
Item 14. Principal Accountant Fees and Services			197
PART IV
Item 15. Exhibits and Financial Statement Schedules			198
Signatures			199

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,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “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) changes in or challenges to our tariff rates; (7) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (8) permitting at federal, state and local levels in regards to the construction of new assets.

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:

AEDC			Allowance for equity 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
Bbl			Barrel of liquids (approximately 42 United States gallons)
Bcf/d			Billion cubic feet per day
BLLP			Beaver Lodge Loop Project
Bpd			Barrels per day
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
CFTC			Commodity Futures Trading Commission
CO2e			Carbon Dioxide Equivalent
Credit Facilities			364-Day Credit Facility and the Credit Facility
CWA			Clean Water Act
DBRS			Dominion Bond Rating System
DCF			Discounted Cash Flow
DOE			United States Department of Energy
DOJ			United States Department of Justice
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.
EBITDA			Earnings Before Interest, Taxes, Depreciation and Amortization
EDA			Equity Distribution Agreement
EES			Enbridge Employee Services Inc., a subsidiary of our General Partner
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.

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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
Exchange Act			Securities Exchange Act of 1934, as amended
FERC			Federal Energy Regulatory Commission
FIP			Federal Implementation Plan
FSM			Facilities Surcharge Mechanism
GDP			Gross Domestic Product
General Partner			Enbridge Energy Company, Inc., the general partner of the Partnership
GHG PSD			Greenhouse Gas Prevention of Significant Deterioration
HB 500			House Bill 500
HCDP Plants			Hydrocarbon dewpoint control facilities
High Prairie			High Prairie Pipelines L.L.C.
IBES			Institutional Brokers’ Estimate System
ICA			Interstate Commerce Act
ISDA®			International Swaps and Derivatives Association, Inc.
IJT			International Joint Tariff
IRS			Internal Revenue Service
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
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
Mcf			Thousand cubic feet
MDEQ			Michigan Department of Environmental Quality
MDNRE			Michigan Department of Natural Resources and Environment
MEP			Midcoast Energy Partners, L.P.
MEP General Partner			Midcoast Holdings, L.L.C.
Midcoast Operating			Midcoast Operating, L.P., the operating subsidiary of MEP
MLP			Master Limited Partnership
MMBtu/d			Million British Thermal units per day
MMBbls			Million Barrels of liquids
MMcf/d			Million cubic feet per day
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
Moody’s			Moody’s Investors Service

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NEB			National Energy Board, a Canadian federal agency that regulates Canada’s energy industry
NGA			Natural Gas Act of 1938
NGLs			Natural gas liquids
NGPA			Natural Gas Policy Act of 1978
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
NSPS			New Source Performance Standards
NTSB			National Transportation Safety Board
NYSE			New York Stock Exchange
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
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
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 of 2006			Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006
Ppb			Parts per billion
PPI-FG			Producer Price Index for Finished Goods
PSA			Pipeline Safety Act of 1992
ROE			Return on Equity
SAGD			Steam assisted gravity drainage
S&P			Standard & Poor’s
SEC			United States Securities and Exchange Commission
SEP II			System Expansion Program II, an expansion program on our Lakehead system
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
SIP			Texas State Implementation Plan
SO2			Sulfur Dioxide
SORA			Submerged Oil Recovery and Assessment workplan
Southern Access			Southern Access Pipeline, a 42-inch pipeline that runs from Superior, Wisconsin to Flanagan, Illinois on our Lakehead system
Suncor			Suncor Energy Inc., an unrelated energy company
Syncrude			Syncrude Canada Ltd., an unrelated energy company

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Tariff Agreement			A 1998 offer of settlement filed with the FERC
TRRC			Texas Railroad Commission
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
VOC			Volatile Organic Compound
WCSB			Western Canadian Sedimentary Basin

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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.

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The following chart shows our organization and ownership structure as of December 31, 2015. 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.

Our Major Projects group is committed to executing and completing projects safely, on time and on budget. These include new builds, organic growth and expansion projects.

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.

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 are well positioned to pursue opportunities for 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 Enbridge 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 2015, 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 2015 from the United States Department of Energy’s, or DOE, Energy Information Administration, or EIA, Canada supplied approximately 3.1 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 Mainline system. The Canadian Association of Petroleum Producers, or CAPP, forecasts as of June 2015 that future production from the Alberta oil sands will continue to experience steady growth during the next two decades with an additional 1.7 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 continued to experience growth 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 has doubled to 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, 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 933 in-line inspections and 13,005 pipeline integrity verification digs completed by Enbridge and us from 2010 through 2015.

We have a multi-billion dollar growth program underway, with projects coming into service through early 2019 in addition to options to increase our economic interest in projects that are jointly funded by us and Enbridge. As part of this growth 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 recent 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 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. Some of these projects include the Eastern Access and Mainline Expansions, as well as the Sandpiper project.

In addition to the Light Oil Market Access Program, we and Enbridge announced the Line 3 Replacement Program. While the Line 3 Replacement Program will not provide an increase in the overall capacity of the mainline system, it 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 Light Oil Market Access projects, 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.

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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. 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 despite 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. We may also target future growth in areas where we can deploy our successful operating strategy to expand our portfolio into other natural gas production regions. Our Natural Gas business also includes trucking, 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 natural gas markets 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.

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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 current 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 natural gas prices recover to the level that will incentivize producers to drill their lean gas 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.

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 16. 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				73
Mid-Continent			433				100				23.6				10
North Dakota			683				31				1.8				23
Total			6,138				208				43.5				106

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 35 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 province of Ontario, Canada. The Lakehead system is the U.S. portion of Enbridge Inc.’s 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 six 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).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.

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Customers.  Our Lakehead system operates under month-to-month transportation arrangements with our shippers. During 2015, 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.

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 Saudi Arabia and Venezuela, respectively. The NEB estimates that 98% 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 168.1 billion total barrels, or approximately 166.3 billion and 1.8 billion barrels of established proved bitumen and conventional reserves, respectively, remain for the region as of 2015. The NEB estimates that total production from the WCSB averaged approximately 3.6 million Bpd in 2015 and 3.5 million in 2014. 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.

North Dakota’s Bakken resource play has grown since 2010, and has become a major component of United States domestic supply. Lakehead throughput volumes are primarily supplied by crude oil produced in the Canadian oil sands and Bakken resource plays. Crude oil supply from the Bakken region has outperformed historical expectations as production now exceeds 1.2 million Bpd, with projections of stabilizing at that level or growing at a low rate due to low oil prices. Forecasts of Western Canadian crude oil supply are periodically completed by Enbridge, CAPP and the NEB, among others. Western Canada oil sands production is expected to grow by 1.7 million Bpd to over 3.9 million Bpd by 2030. This compares with an expected decrease of 100,000 Bpd from conventional production sources over the same time frame. CAPP revised its oil sands production forecast downward by 900,000 Bpd in 2015 from 4.8 million Bpd to 3.9 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 2.3 million Bpd of actual deliveries experienced during 2015.

The latest data available from the EIA shows that total PADD II demand was 3.5 million Bpd. PADD II produced 1.9 million Bpd and imported 2.1 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 63% or 1.3 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 2015 were approximately 202,000 Bpd higher than delivery volumes for 2014. Total deliveries from our Lakehead system averaged 2.3 million Bpd in 2015, meeting approximately 76% of the refinery capacity in the greater Chicago area; 76% of the Minnesota refinery capacity; and 84% of Ontario refinery

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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 3.5 million Bpd, an increase of only 23,000 Bpd from 2014. Moreover, overall refining utilization remained relatively flat in 2015 compared to 2014 for PADD II as utilization fell approximately 0.3%.

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 2015.

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:

		2015				2014				2013				2012				2011
		(thousands of Bpd)
United States
Light crude oil			500				496				473				521				473
Medium and heavy crude oil			1,364				1,167				948				879				850
NGL			5				6				6				5				4
Total United States			1,869				1,669				1,427				1,405				1,327
Ontario
Light crude oil			294				298				247				228				220
Medium and heavy crude oil			77				72				76				85				84
NGL			75				74				66				72				69
Total Ontario			446				444				389				385				373
Total Deliveries			2,315				2,113				1,816				1,790				1,700
Barrel miles (billions per year)			640				582				487				480				450

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 and Flanagan, Illinois. 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.

The storage terminals consist of 100 individual storage tanks ranging in size from 78,000 to 575,000 barrels. Of the approximately 23.6 million barrels of storage shell capacity on our Mid-Continent system, the Cushing terminal accounts for approximately 20.1 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 2015, approximately 47 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. Average deliveries on the Ozark pipeline system were 212,000 Bpd for 2015 up from 200,000 Bpd for 2014.

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 addition, the Cushing terminal remains in high demand as a result of superior connectivity. Despite low commodity prices, we anticipate an increase in volumes on the Mid-Continent system as a result of Enbridge’s Flanagan South Pipeline and other newly constructed third-party pipelines. In 2015, PADD II imported 2.1 million Bpd from outside of the PADD II region, 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.

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, anticipated completion of an additional third-party pipeline in late 2016 will allow the delivery of commodities similar to those currently delivered by our Ozark pipeline, potentially impacting our current competitive advantages. To date, our Ozark system has remained full. If a negative impact does occur to the volumes on our Ozark system, we will consider alternative uses for our Ozark system.

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. 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. 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 100 different receipt facilities located throughout western North Dakota and eastern Montana, including nearly 20 third party gathering pipeline connections, and deliver a fungible common stream to a variety of interconnecting pipeline and rail export facilities.

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 and rail export 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.

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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 2015, approximately 140 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 1.2 million Bpd as of November 2015 with projections of stabilizing at that level or growing at a low rate due to low oil prices.

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 more than 40% of the total Bakken crude exported from North Dakota. Rail provides some advantages to pipeline transportation, but future Enbridge pipeline expansions and enhanced market access to Eastern Canadian markets and eastern PADD II are reducing these advantages when it comes to shipping alternatives. 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.

There are 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.

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 trucking, 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.

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)(4)				Number of active natural gas processing plants				Number of standby natural gas processing plants				Number of active natural gas treating plants				Number of standby natural gas treating plants
Anadarko system			3,200				61				5				7				—				1
East Texas system(1)			4,000				176				6				1				5				4
North Texas system			3,700				29				6				—				—				—
Total			10,900				266				17				8				5				5
Texas Express NGL system(2)			—				709	(3)			—				—				—				—

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Anadarko System

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

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

Our Anadarko system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the Mid-Continent and Gulf Coast regions of the United States. 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 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, James Lime, Rodessa, and Pettite. The East Texas wells generally have long lives with predictable flow rates.

The Eaglebine is an emerging oil play in East Texas that spans over five counties and is comprised of multiple formations, including but not limited to, the Woodbine, Buda, Glenrose and Eagle Ford formations. We have a series of construction projects and an acquisition in this play. In February 2015, we acquired from NGR its midstream operations, which consist of a natural gas gathering system, in Leon, Madison and Grimes counties, Texas. We have completed construction of the Ghost Chili pipeline project, which consists of lateral and associated facilities that create gathering capacity of over 50 MMcf/d for rich natural gas to be delivered from Eaglebine production areas to our complex of cryogenic processing facilities in East Texas. The initial facilities were placed in service in October 2015. We also expect to construct the Ghost Chili Extension Lateral to fully utilize this gathering capacity with the rest of our processing assets when additional development in the basin supports it. Given the proximity of our existing East Texas assets, this expansion into Eaglebine will allow us to offer gathering and processing services while leveraging assets on our existing footprint.

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. Production from the Cotton Valley formation typically contains two to three gallons of NGLs per Mcf of natural gas. 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 2015, 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.

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

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predictable flow rates. As producers have shifted from drilling dry natural gas to rich gas from crude oil production, we have seen our natural gas volumes decline.

Our North Texas system has numerous market outlets for the natural gas that we gather and process and NGLs that we recover on our system. We have connections to major intrastate transportation pipelines that connect our facilities to market centers in the Dallas-Fort Worth area and ultimately to major market hubs in the United States Gulf Coast. All of our owned condensate and NGLs produced at our North Texas system processing plants is sold to our trucking and marketing business.

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. The Texas Express NGL system commenced startup operations during the fourth quarter of 2013. Volumes from the Rockies, Permian basin and Mid-Continent regions are delivered to the Texas Express NGL system utilizing Enterprise Products Partners’ existing Mid-America Pipeline between the Conway hub and Enterprise Products Partners’ Hobbs NGL fractionation facility in West Texas. In addition, volumes from and to the Denver-Julesburg basin in Weld County, Colorado can access the system through the Front Range Pipeline which is owned by Enterprise Products Partners, DCP Midstream and Anadarko Petroleum Corporation.

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

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 horizontal 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 have declined in the second half of 2014 and in 2015. 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 for 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 and are being constructed in areas currently served by our natural gas transportation pipelines. Some of these new pipelines may compete for customers with our existing pipelines.

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Trucking and Marketing Operations

The primary role of our trucking and 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 trucking and marketing business derives operating income from providing trucking services for our customers from the wellhead to markets.

The physical assets of our trucking and 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 trucking and marketing services provided. These agreements supply us with the following:

Customers.  Most of our customers are natural gas aggregators, wholesale customers, refiners and petrochemical producers, fractionators, propane distributors and industrial customers, various third parties and end users.

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

Since major market hubs for NGLs and related products are located in the Mid-Continent and Gulf Coast regions of the United States and our trucking and 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 fleet of trucks, trailers and railcars 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 trucking and marketing business is our natural gas and NGL purchase and resale activities. Through our natural gas and NGL purchase and resale services, we can efficiently manage the transportation and delivery of natural gas from our gathering, processing and transportation 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 trucking and marketing operations have numerous competitors, including large 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, collectively called “petroleum pipelines” or “liquids pipelines.” 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.

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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 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 4.6%, 3.9%, and 4.6% for 2013, 2014 and 2015, 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.

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.

FERC Return on Equity Policy for Oil Pipelines

The FERC 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 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.

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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 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.

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

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NGL Pipeline Regulation

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

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

Two of our other NGL lines, which do not provide service to third parties, operate under FERC-granted waivers from the reporting requirements of Sections 6 and 20 of the ICA. These waivers are effective until a third party shipper requests service. In addition, certain of our NGL lines are subject to regulation as a common carrier by the TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates we charge for NGL transportation service are deemed just and reasonable under Texas law unless challenged by a complaint. Complaints to state agencies have been infrequent and are usually informally resolved. 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 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.

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Tariffs and Transportation Rate Cases

Lakehead system

Under the published rate tariff as of December 31, 2015 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		$	0.4424			$	0.4683			$	0.5141
To Superior, Wisconsin		$	0.9244			$	0.9869			$	1.0962
To Chicago, Illinois area		$	2.0204			$	2.1725			$	2.4394
To Marysville, Michigan area		$	2.4326			$	2.6177			$	2.9425
To Buffalo, New York area		$	2.4925			$	2.6826			$	3.0151
Clearbrook, Minnesota to Chicago		$	1.7944			$	1.9206			$	2.1418

The transportation rates as of December 31, 2015 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 base portion of the transportation rates for our Lakehead system 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.

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 data from the prior year.

The FERC permitted 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, 2015, 24 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 1, 2014, Enbridge filed a Supplement to the Settlement in Docket No. OR15-4-000 seeking approval for the recovery of the costs associated with the “2015-16 Mainline and Eastern Access Expansions” projects in future tariff filings. The FERC accepted the Supplement on February 2, 2015, which included the following projects:

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On December 19, 2014, Flint Hills Resources, L.P., or Flint, filed a Motion to Intervene and Request for Clarification or, In the Alternative Protest, and on December 29, 2014, Suncor Energy Marketing Inc., or Suncor, filed a Motion to Intervene and Protest the Supplement filing. Suncor requested that the FERC defer action on the Supplement until after Lakehead filed a tariff incorporating the new project and that the tariff be allowed to go into effect subject to refund. On January 8, 2015, Enbridge filed a Reply to Flint’s Request for Clarification and Suncor’s Protest. Enbridge addressed the issues raised and requested that the FERC approve the FSM Supplement. On February 2, 2015, the FERC accepted the Supplement to the Settlement in Docket No. OR15-4-000 to permit the recovery of costs associated with the 2015-16 Mainline and Eastern Access Expansions projects.

On February 27, 2015, Enbridge filed FERC tariff 43.16.0 which included the costs related to the expansion of Line 67 to 800,000 Bpd, the expansion of Line 61 to 800,000 Bpd and the construction of Line 78.

The Lakehead system was subject to one protest in 2015 in relation to FERC tariff 43.16.0. Suncor filed a protest on March 16, 2015, claiming that Enbridge had used an outdated base capacity that would result in an over-collection of approximately $94.6 million per year, and therefore that the rates were unjust and unreasonable. Enbridge filed a response on March 20, 2015, stating that the FSM calculation methodology was correct and has remained unchanged since its inception in 2004, and thus that Suncor’s protest was invalid. On March 31, 2015, the FERC issued an order dismissing Suncor’s protest and accepting the tariff filing. On April 30, 2015, Suncor filed a Request for Rehearing, and on August 18, 2015, the FERC issued an Order Denying Rehearing.

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 provision of tank service.

As of December 31, 2015, the FSM was $1.0515 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. 45.7.0, issued May 29, 2015, revised the International Joint Tariff, or IJT, effective July 1, 2015, by increasing the transportation tolls by 1.42%. 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 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.

Mid-Continent system

Our 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, 2015, our Ozark system filed FERC Tariff 48.5.0 to increase its rate in compliance with the indexed rate ceilings allowed by the FERC by incorporating the multiplier of 1.045829 that was issued by the FERC in Docket No. RM93-11-000 on May 14, 2015.

Effective December 1, 2015, our Ozark system filed FERC Tariff 48.6.0 to increase its rate from $0.6759 to $0.8403. This filing was made to allow for recovery of costs related to the capital expenditures required to maintain the integrity of the pipeline.

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The transportation rate for light crude oil on our 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 system consists of both gathering and trunkline assets. 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 volumes 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 is applied to volumes originating at Trenton, Little Muddy or Alexander, North Dakota. Effective April 1, 2010, the term of the looping surcharge on our North Dakota system was extended by four years, ending 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 is in addition to existing base rates and the Phase 5 surcharges and is adjusted on an annual basis to actual costs and volumes. It is not subject to the FERC index methodology. The Phase 6 surcharge became effective on January 1, 2010 and will expire on December 31, 2016.

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 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 Project went into service on March 1, 2013.

On November 2, 2012, the North Dakota system submitted a Petition for Declaratory Order seeking approval of a related Offer of Settlement with respect to a major expansion and extension of the North Dakota system called the Sandpiper Project. The project will result in a substantial increase in the capacity available to transport Bakken crude both to and through Clearbrook, Minnesota to Superior, Wisconsin. The terms of the proposal include, among other things, the addition of a cost-of-service rate surcharge to the existing rates to Clearbrook, and a new cost-of-service tariff rate from Clearbrook to Superior. On March 22, 2013, the Petition was denied by the FERC on the basis that an Offer of Settlement requires the unanimous approval of all shippers. A revised proposal for the Sandpiper Project, including the availability of contracted space on the pipeline, is currently being offered to shippers through a successful open season and on February 19, 2014, a revised Petition for Declaratory Order was filed with the FERC. In this petition, the North Dakota system proposed a tariff structure that involves separate rates for committed priority volumes, committed non-priority volumes, and uncommitted volumes. On May 15, 2014, the Petition for Declaratory Order was approved by the FERC in Docket No. OR14-21-000.

Effective February 1, 2015, FERC tariff No. 3.6.0 established a new interconnection at Tioga, North Dakota.

Effective April 1, 2015, FERC tariff No. 3.7.0 updated the calculation of the Phase 5 Looping and Phase 6 Mainline surcharges. These surcharges are cost-of-service based surcharges that are adjusted each year to actual costs and volumes and are not subject to the FERC indexing methodology. The filing decreased our average transportation rates for all crude oil movements on our North Dakota system with a destination of Clearbrook, Minnesota by an average of approximately $0.44 per barrel, to an average of approximately $1.77 per barrel. The Phase 5 Looping surcharge decreased primarily due to an increase in forecasted throughput, and the Phase 6 Mainline surcharge decreased due to an increase in forecasted throughput and in order to return prior period over-recoveries to shippers.

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Effective April 22, 2015, FERC tariff No. 3.8.0 cancelled the transportation rate from Sherwood, North Dakota to Clearbrook, Minnesota, as the pipeline no longer provides service from that receipt point.

Effective July 1, 2015, FERC tariff No. 3.10.0 increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 1.045829 issued by the FERC on May 14, 2015, in Docket No. RM93-11-000. Additionally, as per the Transportation Services Agreement, or TSA, this tariff adjusted the operating cost charge component of the committed trunkline rates to Berthold, North Dakota to the actual operating costs and throughput volumes for 2014 and the forecasted operating costs and throughput for 2015.

Also effective July 1, 2015, FERC tariff No. 3.11.0 discounted the existing uncommitted rate from Berthold (pump-over), North Dakota to Berthold, North Dakota. The new tariff rate of $0.27 per barrel reflects a rate decrease of $0.556 per barrel.

Effective December 1, 2015, FERC tariff 3.13.0 was filed to establish an initial gathering service and charge at Little Muddy (Williams County), North Dakota. The $0.1137 per barrel interconnection rate resulted from a shipper’s request for a pipeline interconnection at that location.

Effective December 16, 2015, FERC tariff 3.15.0 was filed to cancel trunkline transportation rates from Glenburn (Renville County), North Dakota and Newburg (Bottineau County), North Dakota to Clearbrook (Clearwater County), Minnesota, as well as to cancel the gathering rate from Newburg Area, North Dakota to Newburg (Bottineau County), North Dakota, as the pipeline is no longer providing service from those receipt points.

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

		Published Transportation Rate Per Barrel(1)
From Minot, Berthold and Stanley, North Dakota to Clearbrook, Minnesota		$	1.5269
From Grenora, North Dakota to Clearbrook, Minnesota		$	1.6920
From Reserve, Montana to Clearbrook, Minnesota		$	1.7285
From Tioga, North Dakota to Clearbrook, Minnesota		$	1.5631
From Trenton, North Dakota to Clearbrook, Minnesota		$	2.0705
From Alexander, North Dakota to Clearbrook, Minnesota		$	2.1251
From Little Muddy, North Dakota to Clearbrook, Minnesota		$	2.0705
From Grenora, North Dakota to Tioga, North Dakota		$	0.6420
From Reserve, Montana to Tioga, North Dakota		$	0.6785
From Trenton, North Dakota to Tioga, North Dakota		$	0.8736
From Alexander, North Dakota to Tioga, North Dakota		$	0.9281
From Little Muddy, North Dakota to Tioga, North Dakota		$	0.8736
From (pump-over) Stanley, North Dakota to Stanley, North Dakota		$	0.2842
From Tioga, North Dakota to Stanley, North Dakota		$	1.0400
From Grenora, North Dakota to Stanley, North Dakota		$	1.1881
From Reserve, Montana to Stanley, North Dakota		$	1.2217
From Trenton, North Dakota to Stanley, North Dakota		$	1.5519
From Alexander, North Dakota to Stanley, North Dakota		$	1.6023
From Little Muddy, North Dakota to Stanley, North Dakota		$	1.5519
From Berthold, North Dakota to Berthold, North Dakota		$	0.2700
From Stanley, North Dakota to Berthold, North Dakota		$	0.9491
From Tioga, North Dakota to Berthold, North Dakota		$	1.0400

Bakken System

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.

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Local Tariff

Effective July 1, 2014, the North Dakota system filed on behalf of the Bakken system FERC tariff 2.1.0. The tariff increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporated the multiplier of 1.038858 issued by the FERC on May 14, 2014 in Docket No. RM93-11-000.

Effective July 1, 2015, the North Dakota system filed on behalf of the Bakken system FERC tariff 2.2.0. The tariff increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporated the multiplier of 1.045829 issued by the FERC on May 14, 2015, in Docket No. RM93-11-000.

The rates and surcharges for transportation of light crude oil on our Bakken system are set forth below:

		Published Transportation Rate Per Barrel(1)
From Berthold, North Dakota to the international border near Portal, North Dakota		$	1.2990

International Joint Tariff

Effective July 1, 2014, the Bakken system filed FERC tariff 3.1.0. 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. OR10-10-000. This filing also 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 based 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 initial operating costs charge at the in-service date for Bakken on March 1, 2013, was $0.33. With the aforementioned filing, the operating costs charge decreased to $0.24.

Effective July 1, 2015, the Bakken system filed FERC tariff 3.4.1. 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. The operating cost charge for Bakken as of July 1, 2015, decreased by $0.36 to a credit of $0.12 as an adjustment for an over recovery in the prior year.

Safety Regulation and Environmental

General

Our transmission and gathering pipelines, storage and processing facilities, trucking 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 DOT and 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.

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.

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

Environmental Regulation

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

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

There are also risks of accidental releases into the environment associated with our operations, such as releases or spills of crude oil, 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 permits and approvals for any new or acquired facilities. The operations of our pipeline facilities are subject to the Environmental Protection Agency’s, or EPA, Spill Prevention, Control, and Countermeasures Rule and we are currently in full compliance. Our facilities subject to existing EPA Greenhouse Gas Reporting rules have reported emissions prior to the annual filing deadlines.

On October 31, 2014, the Texas State Implementation Plan received the authority to regulate greenhouse gas emissions and approve Greenhouse Gas Prevention of Significant Deterioration, or GHG PSD, permits in Texas. This approval authority should simplify the GHG PSD permitting process in Texas. On November 10, 2014, the EPA rescinded a Federal Implementation Plan, or FIP, for Texas for GHG PSD permitting.

The EPA published its final New Source Performance Standards, or NSPS, Subpart OOOO and National Emission Standards for Hazardous Air Pollutants, or NESHAP, Subpart HHH, for volatile organic compounds, or VOCs, and sulfur dioxide, or SO2, emissions from the oil and natural gas sector, which became effective on August 16, 2012. On September 18, 2015, the EPA published a proposed rule, Subpart OOOOa, which would

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update the original 2012 standards to include additional reductions in methane and VOCs in the oil and gas industry. On November 26, 2014, the EPA announced its intentions to strengthen air quality standards to within a range of 65 to 70 parts per billion, or Ppb, for ozone. The EPA last updated these standards in 2008, then setting the standard at 75 Ppb. On October 1, 2015, the EPA strengthened the National Ambient Air Quality Standards, or NAAQS, for ground-level ozone to 70 Ppb. As a result of the more stringent standard, numerous counties fall into the non-attainment category, resulting in more costly pollution control requirements.

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. The EPA’s response stated that natural gas processing facilities may be appropriate for addition to the scope of the TRI and will likely commence the rulemaking process to include these facilities in the reporting requirements. We operate facilities that may be impacted by this change, if implemented.

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.

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

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

Site Remediation.  We own and operate a number of pipelines, gathering systems, storage facilities and processing facilities that have been used to transport, distribute, store and process 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

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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, 2016. 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 coverage limits and deductible amounts at December 31, 2015 for our insurance policies:

Insurance Type		Coverage Limits				Deductible Amount
		(in millions)
Property and business interruption			Up to $800.0			$	10.0
General liability			Up to $860.0			$	0.1
Pollution liability (as included under General Liability)			Up to $860.0			$	30.0

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

TAXATION

We are not a taxable entity for U.S. federal income tax purposes. Generally, U.S. federal and state income taxes on our taxable income are borne by our individual partners through the allocation of our taxable income. In 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.

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Item 1A. Risk Factors

We encourage you to read the risk factors below in connection with the other sections of this Annual Report on Form 10-K.

RISKS RELATED TO OUR BUSINESS

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 those prevalent during the recessionary period of 2008 that continued for several years as well as the current decline in commodity prices, periodically result in weakness and volatility in the capital markets, which in turn can limit, temporarily or for extended periods, our ability to raise capital through equity or debt offerings. Additionally, the availability and cost of obtaining credit commitments from lenders can change as economic conditions and banking regulations reduce the credit that lenders have available or are willing to lend. These conditions, along with significant write-offs in the financial services sector and the re-pricing of market risks, can make it difficult to obtain funding for our capital needs from the capital markets on acceptable economic terms. As a result, we may revise the timing and scope of these projects as necessary to adapt to prevailing market and economic conditions.

Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or capital markets on acceptable terms, if needed and to the extent required. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our development plan, enhance our existing business, complete acquisitions and construction projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

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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.

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, 2015, we have provided $120.1 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, 2015, we would have been required to provide additional letters of credit in the aggregate amount of $52.5 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.

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. 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.

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:

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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:

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. 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 is 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.

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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. Growth in production from the oil sands over the past decade has remained strong due to high oil prices and improved production methods; however the industry faces a number of risks associated with the scope and scale of its projects. Factors and risks affecting the oil sands industry include:

Alberta oil sands producers face a number of challenges that must be managed effectively to allow for sustained growth in the sector. The unprecedented level of development in the Alberta oil sands has driven costs upward as a result of a tight labor market, high equipment costs, and costs for commodities such as steel and other raw materials. Labor has been one of the most important considerations for the industry, as worker wages have risen steadily with industry development over the past several years.

The environmental impact of oil sands development in northern Alberta has been at the forefront of discussion around future industry growth in the region. Labor and environmental groups have expressed their views and concerns about oil sands development and pipeline infrastructure in the public domain and in front of regulators. The primary concerns raised include greenhouse gas emissions and environmental monitoring and reclamation. Though industry associations have stated that they are not opposed to changes in policy and regulation to address these concerns, the adoption of new regulation that may curtail oil sands development or adversely impact the oil and gas industry remains a risk and may result in, among other things, significant capital expenditures, increased operating costs, or decreased demand for our products.

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.

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We also encounter competition in our natural gas gathering, treating, and processing and transmission businesses. A number of new interstate natural gas transmission pipelines being constructed 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 gas marketing operations involve market and regulatory risks.

As part of our natural gas, NGL 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 natural gas 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 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.

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Our Natural Gas segment results may 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 2016. Our exposure to commodity price volatility is inherent to our natural gas processing activities. Before hedging, approximately 40% of our gross margin attributable to our natural gas processing activities is expected to be attributable to contracts with some degree of commodity price exposure in 2016. MEP employs a disciplined hedging program to manage this direct commodity price risk.

To the extent that we engage in hedging activities to reduce our commodity price exposure in 2016, we may be prevented from realizing the full benefits of price increases above the level of the hedges. However, because we are not fully hedged, we will continue to have commodity price exposure on the unhedged portion of the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of this unhedged exposure, a substantial decline in the prices of these commodities could adversely affect our results of operation and cash flows and ability to make distributions.

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

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. 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.

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Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could result in significant financial losses.

We use derivative financial instruments to manage the risks associated with market fluctuations in commodity prices, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are associated with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate all risk of unauthorized trading and other speculative activity. Although this activity is monitored independently by our risk management function, we remain exposed to the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detect and prevent all unauthorized trading and other violations of our risk management policies and procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could result in significant financial losses and have a material adverse effect on our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

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

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

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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 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 sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in Congress. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential impacts of hydraulic fracturing on drinking water resources; the multi-year study’s individual research projects began publishing results in 2013, and individual studies are ongoing. In addition, the EPA has announced its intention to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities under the CWA and in a proposed rule published on April 7, 2015. The EPA anticipates finalizing this rule by August 2016. The Department of Interior also issued new regulations governing hydraulic fracturing on public and tribal lands that may impose additional operating costs. The impact of this rule is uncertain because it is subject to ongoing litigation and is currently enjoined pursuant to a court order.

On April 17, 2012, the EPA also approved final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. These new rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through flaring until 2015, after which reduced emission or “green” completions must be used. The rules also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas producing plants, and

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certain other equipment. On April 12, 2013, the EPA proposed amendments to the rule which would, among other things, provide additional time for recently constructed, modified or reconstructed storage tanks to install emission controls.

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.

These rules and proposals may require a number of modifications to our customers’ and our own operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our customers, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations.

Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. For example, on December 13, 2011, the 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 has 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, has followed others in adopting bans or severely restricting hydraulic fracturing activities. Litigation concerning this ban, as well as others, is ongoing. We cannot predict whether any 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 and adversely affect our financial condition, results of operations and cash flows, as well as 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, processing and trucking operations involves many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of the facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes, floods, landslides or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, any of which could also result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. Costs of pipeline seepage over time may be mitigated through insurance, however, if not discovered within the specified insurance time period we would incur full costs for the incident. 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.

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.

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

Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets will require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make distributions to our unitholders. 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 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 were recently 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 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.

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 from making distributions to us in certain circumstances involving certain defaults thereunder or any events of defaults thereunder. 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.

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.

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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 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:

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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 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.

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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:

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.

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RISKS ARISING FROM OUR PARTNERSHIP STRUCTURE

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, 2016. 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 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.

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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 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.

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

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to the unitholder. This allocation of taxable income may require the payment of federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability 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 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 you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

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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 use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly-traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed Treasury Regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may be required to recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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

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

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

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

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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, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

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

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 13. 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 2015 and 2014 are summarized as follows:

		First				Second				Third				Fourth
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
2014 Quarters
High		$	29.94			$	36.95			$	40.10			$	41.68
Low		$	26.30			$	26.00			$	31.78			$	31.63
Cash distributions paid		$	0.54350			$	0.54350			$	0.55500			$	0.55500

On February 12, 2016, the last reported sales price of our Class A common units on the NYSE was $15.57. As of January 22, 2016, there were approximately 928 registered holders of record of Class A common units. The holders of record do 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, 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,
		2015				2014				2013				2012				2011
		(in millions, except per unit amounts)
Income Statement Data:
Operating revenues(9)		$	5,146.1			$	7,964.7			$	7,117.1			$	6,706.1			$	9,109.8
Operating expenses(6)(7)(8)(9)(10)			4,464.5				6,878.0				6,676.7				5,812.9				8,113.0
Operating income			681.6				1,086.7				440.4				893.2				996.8
Interest expense			(322.0	)			(403.2	)			(320.4	)			(345.0	)			(320.6	)
Allowance for equity used during construction(11)			70.3				57.2				43.1				11.2				—
Other income (expense)			29.3				8.9				16.0				(1.2	)			6.5
Income tax benefit (expense)			(4.9	)			(9.6	)			(18.7	)			(8.1	)			(5.5	)
Net income			454.3				740.0				160.4				550.1				677.2
Less: Noncontrolling interest			221.1				263.3				88.3				57.0				53.2
Series 1 preferred unit distributions			90.0				90.0				58.2				—				—
Accretion of discount on Series 1 preferred units			11.2				14.9				9.2				—				—
Income (loss) from continuing operations attributable to general and limited partnership interests		$	132.0			$	371.8			$	4.7			$	493.1			$	624.0
Net income (loss) allocable to common units and i-units		$	(84.8	)		$	218.4			$	(122.7	)		$	369.2			$	520.5
Net income (loss) per common unit and i-unit (basic and diluted)(1)		$	(0.25	)		$	0.67			$	(0.39	)		$	1.27			$	1.99
Cash distributions paid per limited partner unit outstanding		$	2.3060			$	2.1970			$	2.1740			$	2.1520			$	2.0925
Financial Position Data (at year end):
Property, plant and equipment, net		$	17,412.4			$	15,692.7			$	13,176.8			$	10,937.6			$	9,439.4
Total assets			18,815.8				17,746.9				14,901.5				12,796.8				11,370.1
Long-term debt, excluding current maturities(3)			7,769.9				6,675.2				4,777.4				5,501.7				4,816.1
Notes payable to General Partner			—				306.0				318.0				330.0				342.0
Partners’ capital:
Series 1 preferred units(12)			1,186.8				1,175.6				1,160.7				—				—
Class D units(13)			2,517.6				2,516.8				—				—				—
Class E units(14)			778.2				—				—				—				—
Class A common units(4)			—				235.5				2,979.0				3,590.2				3,386.7
Class B common units			—				—				65.3				83.9				82.2
i-units(5)(8)			212.6				712.6				1,291.9				801.8				728.6
Incentive distribution units(15)			495.0				493.0				—				—				—
General Partner			147.4				198.3				301.5				299.0				285.6
Accumulated other comprehensive deficit			(370.0	)			(211.4	)			(76.6	)			(320.5	)			(316.5	)
Noncontrolling interest			3,944.5				3,609.0				1,975.6				793.5				445.5
Partners’ capital		$	8,912.1			$	8,729.4			$	7,697.4			$	5,247.9			$	4,612.1
Cash Flow Data:
Cash flows provided by operating activities(6)(7)(8)(9)(10)		$	1,030.8			$	816.8			$	1,212.4			$	851.0			$	1,045.6
Cash flows used in investing activities		$	2,126.4			$	2,976.6			$	2,642.9			$	1,906.6			$	1,099.0
Cash flows provided by financing activities(3)(4)(5)		$	1,045.8			$	2,192.9			$	1,367.4			$	860.6			$	331.4
Additions to property, plant and equipment, and acquisitions included in investing activities, net of cash acquired(2)		$	2,201.8			$	2,933.8			$	2,410.8			$	1,739.9			$	1,091.8

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Date of Acquisition		Description of Acquisition
February 2015		Acquisition of the midstream business of New Gulf Resources, LLC, or NGR, in Texas.

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
September 2011			4.200% Senior Notes			$	600
September 2011			5.500% 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
2011 Equity Distribution Agreement issuances			Class A				3,084,208			$	95.5
December 2011			Class A				9,775,000			$	298.1
September 2011			Class A				8,000,000			$	222.9
July 2011			Class A				8,050,000			$	238.6
January 2011			Class A				50,650			$	1.6

Fiscal Year		Amount of Distribution of i-units to i-unit Holders(a)				Retained from General Partner				Distribution of Cash
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
2011		$	75.7			$	1.5			$	565.7

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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.

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 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. Additionally, we provide other services that are valued by our customers. 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, 2015, 2014 and 2013:

		December 31,
		2015				2014				2013
		(in millions)
Operating income (loss)
Liquids		$	994.0			$	938.9			$	392.6
Natural Gas			(298.0	)			158.4				55.4
Corporate, operating and administrative			(14.4	)			(10.6	)			(7.6	)
Total operating income			681.6				1,086.7				440.4
Interest expense			(322.0	)			(403.2	)			(320.4	)
Allowance for equity used during construction			70.3				57.2				43.1
Other income			29.3				8.9				16.0
Income tax expense			(4.9	)			(9.6	)			(18.7	)
Net income			454.3				740.0				160.4
Less: Net income attributable to:
Noncontrolling interest			221.1				263.3				88.3
Series 1 preferred unit distributions			90.0				90.0				58.2
Accretion of discount on Series 1 preferred units			11.2				14.9				9.2
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	132.0			$	371.8			$	4.7

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Highlights

Liquids

Our Liquids segment operating income increased $55.1 million for the year ended December 31, 2015, as compared with the same period in 2014, primarily due to additional assets placed in service and an increase in volumes on our systems. In 2014 and 2015, $2.7 billion and $1.6 billion of additional assets, respectively, were placed into service on our Lakehead system, including portions of the Eastern Access, Mainline Expansion projects and other projects. Average daily volumes delivered on our liquids systems increased 249,000 Bpd, or 9.46%, for the year ended December 31, 2015, when compared with the same period in 2014, due to increased capacity. Lastly, the Liquids segment operating income increased as a result of reduced environmental costs, net of recoveries, primarily due to lower environmental accruals, net of recoveries, related to the Line 6B crude oil release.

Natural Gas

Our Natural Gas segment operating income decreased $456.4 million for the year ended December 31, 2015, as compared to the same period in 2014, primarily as a result of a non-cash goodwill impairment charge of $246.7 million that was recorded during the second quarter of 2015. In addition, 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, as compared to gains of $158.5 million for year ended December 31, 2014. Furthermore, there were declines in natural gas pricing differentials and production volumes for the year ended December 31, 2015, when compared to the same period in 2014, primarily due to the current low commodity pricing environment. We expect that the lower commodity price trends will continue through 2016. These decreases in segment gross margin were offset by over $70.0 million of workforce and other cost reductions for the year ended December 31, 2015.

Derivative Transactions and Hedging Activities

Contractual arrangements in our Liquids, Natural Gas, and Corporate segments 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:

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

		December 31,
		2015				2014				2013
		(in millions)
Liquids segment:
Non-qualified hedges		$	(15.5	)		$	13.6			$	(3.9	)
Natural Gas segment:
Hedge ineffectiveness			(4.1	)			5.6				3.3
Non-qualified hedges			(54.2	)			152.9				(6.3	)
Commodity derivative fair value net gains (losses)			(73.8	)			172.1				(6.9	)
Corporate:
Interest rate hedge ineffectiveness			98.9				(100.1	)			(21.5	)
Non-qualified interest rate hedges			—				—				(0.2	)
Derivative fair value net gains (losses)		$	25.1			$	72.0			$	(28.6	)

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,
		2015				2014				2013
		(in millions)
Operating Results:
Operating revenue		$	2,303.4			$	2,070.4			$	1,519.9
Operating expenses:
Environmental costs, net of recoveries			3.1				97.3				273.7
Operating and administrative			605.9				500.8				461.0
Power			259.5				226.6				147.7
Asset Impairment			62.5				—				—
Depreciation and amortization			378.4				306.8				244.9
Total operating expenses			1,309.4				1,131.5				1,127.3
Operating income		$	994.0			$	938.9			$	392.6
Operating Statistics
Lakehead system:
United States(1)			1,869				1,669				1,427
Province of Ontario(1)			446				444				389
Total Lakehead system delivery volumes(1)			2,315				2,113				1,816
Barrel miles (billions)			640				582				487
Average haul (miles)			757				755				735
Mid-Continent system delivery volumes(1)			212				200				201
North Dakota system:
Trunkline(1)			351				315				168
Gathering(1)			2				3				3
Total North Dakota system delivery volumes(1)			353				318				171
Total Liquids segment delivery volumes(1)			2,880				2,631				2,188

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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, primarily due to the following reasons. Operating revenue increased $25.2 million, primarily 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 have not been 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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Year ended December 31, 2014 compared with year ended December 31, 2013

Operating revenue of our Liquids segment increased $550.5 million for the year ended December 31, 2014, when compared with the same period in 2013, primarily due to the filing of tariffs to increase the rates for our Lakehead, North Dakota and Ozark systems with the FERC. These rate increases became effective on April 1 and July 1, 2014, for our North Dakota and Ozark systems, and August 1, 2014, for our Lakehead system. The increase in rates accounted for $339.5 million of the increase in operating revenue for the year ended December 31, 2014, when compared to December 31, 2013. The large increase in rates is primarily due to $2.7 billion of additional assets placed into service in 2014 on the Lakehead system, including the Eastern Access, Mainline Expansion and other expansion projects. Additionally, 2014 revenues increased from a full year of revenue for Lakehead and North Dakota expansion projects placed into service during 2013. The rate increases effective April 1, 2014, primarily resulted from annual tariff filings for our North Dakota and Ozark systems to reflect our projected costs and throughput for 2014 and adjustments for the prior year. The rate increases effective July 1, 2014, resulted from an annual index rate filing to adjust base rates for our North Dakota and Ozark systems in compliance with rate ceilings allowed by the FERC. The rate increases effective August 1, 2014, resulted from tariff filings for our Lakehead system to reflect our projected costs and throughput for 2014, adjustments for the prior year, and an indexing adjustment to base rates in compliance with the indexed rate ceilings allowed by the FERC. Historically, the Lakehead system’s annual tariff filing has been effective April 1 and its annual index rate filing has been effective July 1; however, the filings were delayed due to negotiations with CAPP concerning certain components of the tariff rate structure.

Operating revenue also increased for the year ended December 31, 2014, when compared to the same period in 2013, by $139.9 million due to increased average daily delivery volumes on our Lakehead and North Dakota systems. Average daily volumes delivered on our liquids systems increased 443,000 Bpd for the year ended December 31, 2014, compared to the year ended December 31, 2013. Of that amount, our Lakehead system realized higher daily volumes of 297,000 Bpd, which contributed to increased revenue of $75.7 million. This increase in volumes is attributable to a combination of increased supply from Western Canada and additional capacity on our system from the assets placed into service in 2014 as discussed above. The North Dakota system also experienced an increase of 147,000 Bpd primarily due to narrowing market pricing differentials from North Dakota to major market centers. This reduction in pricing differentials shifted volumes onto our North Dakota system and away from rail competitors.

Additionally, operating revenue increased during the year ended December 31, 2014, when compared to the same period in 2013, due to an increase of $17.6 million primarily from our Berthold Rail System that was placed into service in March 2013.

Operating revenue increased for the year ended December 31, 2014, when compared with the same period in 2013, due to an increase of $24.2 million in ship-or-pay contracts on our North Dakota and Bakken systems. This is primarily due to increased committed volumes for certain shippers.

Additionally, operating revenue increased as a result of increases of $17.3 million of non-cash, mark-to-market net gains related to derivative financial instruments. The increase is the result of $2.3 million in realized gains related to our settled derivative financial instruments, coupled with $15.0 million of non-cash, mark-to-market net gains due to decreases in average forward prices of crude oil during 2014, compared to increases in the average forward prices of crude oil during 2013.

Environmental costs, net of recoveries, decreased $176.4 million for the year ended December 31, 2014, when compared with the same period in 2013, primarily due to lower environmental accruals, net of recoveries, related to the Line 6B crude oil release. During the year ended December 31, 2014, we recognized $85.9 million in cost accruals compared to $302.0 million for the comparable period ended December 31, 2013. There were no insurance recoveries during 2014 compared to $42.0 million during 2013.

Operating and administrative expenses increased $39.8 million for the year ended December 31, 2014, when compared with the same period in 2013, primarily due to: $40.4 million of workforce related costs; $18.6 million of property taxes; and $34.3 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. The increase in operating and administrative expenses is offset by a decrease of $53.9 million of pipeline integrity costs primarily due to $57.7 million of costs incurred for a hydrostatic test we performed on Line 14 during 2013 that did not occur again during 2014.

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Power costs increased $78.9 million for the year ended December 31, 2014, when compared to the year ended December 31, 2013, primarily as a result of increased volumes on our systems.

The increase in depreciation expense of $61.9 million for the year ended December 31, 2014, is directly attributable to additional assets placed into service, primarily on projects discussed above. The increase in depreciation expense was offset by a $12.6 million reduction due to depreciation studies we completed during the fourth quarter of 2013 for our North Dakota and Ozark systems. The depreciation studies extended the asset lives due to additional reserve growth and pipeline connectivity needs, and the total impact of these studies is a reduction of annual depreciation expense of $16.8 million on a prospective basis.

Future Prospects Update for Liquids

We currently have a multi-billion dollar growth program underway, with projects coming into service through early 2019, in addition to options to increase our economic interest in projects that are jointly funded by us and Enbridge. Furthermore, Enbridge has a large inventory of United States liquids pipelines assets and continues to evaluate selective drop down opportunities of approximately $500 million annually, subject to market conditions and our financing capacity.

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 involves 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 materially impact projected growth from the oil sands region.

We expect that the current crude oil price downturn may result in deferral of some oil sands projects, particularly if the current pricing environment continues throughout 2016. 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 one of the oil sands operations. Accordingly, we do not anticipate significant changes in our short-term crude oil volume outlook from the oil sands. 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 ideally positioned to capture incremental pipeline capacity needs with lower cost, smaller scale expansions of our large Lakehead, North Dakota and Mid-Continent pipeline systems.

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.

Financial impacts to our pipeline systems, in the event the rate of growth were to slow or volumes were to decline, is partially offset by our cost-of-service agreements, toll structures and existing demand to transport crude oil from existing production. 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 that have been recently placed into service or will be placed into service in future periods:

Projects

Total Estimated Capital Costs

In-Service Date

Funding

(in millions)

Line 3 Replacement Program(1)

$

2,600

Early 2019

EEP

(2)

Sandpiper Project(1)

2,600

Early 2019

Joint

(3)

Eastern Access Projects:

Eastern Access Upsize – Line 6B Expansion

310

Mid-2016

Joint

(4)

U.S. Mainline Expansions:

Chicago Area Connectivity (Line 78)

540

Fourth quarter 2015

Joint

(5)

Line 61 (800,000 Bpd capacity)

395

Second quarter 2015

Joint

(5)

Line 61 (Additional tankage)

380

Third quarter 2015 – Third quarter 2016

Joint

(5)

Line 61 (1,200,000 Bpd capacity)(6)

485

Early 2019

Joint

(5)

Line 67

240

Third quarter 2015

Joint

(5)

Line 3 Replacement Program

On March 3, 2014, we and Enbridge 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. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the system, enhance flexibility and allow us and Enbridge to optimize throughput on the mainline system 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 Minnesota Public Utilities Commission, or MNPUC. The MNPUC found both the Certificate and Route Permit applications for the US L3R Program through Minnesota to be complete. The MNPUC had sent the Certificate application to the Administrative Law Judge, or ALJ, for a pre-hearing meeting to establish a schedule. With respect to the Route Permit, the Minnesota Department of Commerce held public scoping meetings in August 2015. As a result of the Minnesota Court of Appeals decision for the Sandpiper Project, the ALJ requested direction on how to proceed with the Certificate process for Line 3. 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 Department of Commerce to prepare an 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. We believe that the directions from the MNPUC in most of the decisions set out in the US L3R Order were consistent with expectations and provide clarity on process matters; however, we believe the requirement to have a final EIS prior to beginning the Certificate and Route Permit processes is unprecedented and contrary to Minnesota law. On February 5, 2016, we filed a Petition for Reconsideration of this aspect of the US L3R Order. If upheld, the US L3R Order will result in delays in the processing of the applications and an increase in the costs of the project.

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Subject to regulatory and other approvals, the US L3R Program is now expected to be completed in early 2019. We continue to review the impact of this order on the US L3R Program’s schedule and cost estimates. 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 joint funding arrangements for the US L3R Program by creating an additional jointly owned series of partnership interests in Enbridge Energy, Limited Partnership, or OLP, similar to the series established for Eastern Access and Mainline Expansion.

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 recent 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 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.

Sandpiper Project

Included in the Light Oil Market Access Program is the Sandpiper Project which will expand and extend the North Dakota feeder system by 225,000 Bpd to a total of 580,000 Bpd. The proposed expansion will involve construction of an approximate 600-mile pipeline from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line will twin the existing 210,000 Bpd North Dakota system mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 250,000 Bpd of capacity on the twin line between Tioga and Berthold, North Dakota and 225,000 Bpd of capacity on the twin line between Berthold and Clearbrook both with a new 24-inch diameter pipeline, in addition to adding 375,000 Bpd between Clearbrook and Superior with a new 30-inch diameter pipeline.

We are in the process of obtaining the appropriate permits for the construction of the Sandpiper Project in Minnesota. The project requires both a Certificate and Route Permit from the MNPUC. On August 3, 2015, the MNPUC issued an order granting a Certificate and a separate order restarting the Route Permit proceedings. On September 14, 2015, the Minnesota Court of Appeals reversed the MNPUC’s Certificate order stating that an EIS must be prepared prior to reaching a final decision in cases where proceedings have been separated and handled sequentially. On January 11, 2016, the MNPUC issued a written order, or the Sandpiper Order, rejoining the Certificate and Route Permit process, requiring the Department of Commerce to commence preparation of an EIS, ordering the OAH to recommence processing the Certificate and Route Permit applications but to take judicial notice of the record already developed for the Certificate, and requiring that a final EIS be issued before the Certificate and Route Permit processes commence. We believe that the directions from the MNPUC in most of the decisions set out in the Sandpiper Order were consistent with expectations and provide clarity on process matters; however, we believe the requirement to have a final EIS prior to beginning the Certificate and Route Permit processes is unprecedented and contrary to Minnesota law. On February 1, 2016, we filed a Petition for Reconsideration for this aspect of the Sandpiper Order. If upheld, the Sandpiper Order will result in delays in processing of the applications and an increase in the cost of the project. Subject to regulatory and other approvals, we estimate that the in-service date for the Sandpiper Project will occur in early 2019. We continue to review the impact of the Sandpiper Order on the project's schedule and cost estimates.

Marathon Petroleum Corporation, or MPC, has been secured as an anchor shipper for the Sandpiper Project. As part of the arrangement, we, through our subsidiary, North Dakota Pipeline Company LLC, or NDPC, and Williston Basin Pipeline LLC, or Williston, an affiliate of MPC, entered into an agreement to, among other things, admit Williston as a member of NDPC. Williston will fund 37.5% of the Sandpiper Project construction and have the option to participate in other growth projects within NDPC, unless specifically excluded by the agreement; this investment is not to exceed $1.2 billion in aggregate. In return for funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in-service date of Sandpiper.

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Eastern Access Projects

Since October 2011, we and Enbridge have announced multiple expansion projects that will provide 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. As part of the Light Oil Market Access Program announced in 2012, we announced a further expansion project of Line 6B to increase capacity from 500,000 Bpd to 570,000 Bpd and to include: pump station modifications at Griffith, Niles and Mendon, Indiana; additional modifications at the Griffith and Stockbridge, Michigan terminals; and breakout tankage at Stockbridge. The expected cost of this expansion is approximately $310 million and is expected to be placed into service in mid-2016. This project is being funded 75% by our General Partner and 25% by us under the Eastern Access Joint Funding Agreement. Within one year of the in-service date, we will have the option to increase our economic interest by up to 15% at cost. The Eastern Access Projects, which includes the Line 6B Expansion project along with the previously completed Line 5 Expansion, Line 62 Expansion and the Line 6B Replacement projects, will cost approximately $2.7 billion.

U.S. Mainline Expansions

In 2012 and 2013, we announced further expansion projects for our mainline pipeline system including: (1) expanding our existing 36-inch diameter Alberta Clipper pipeline, or Line 67; (2) expanding our existing 42-inch diameter Southern Access pipeline, or Line 61; and (3) expanding by constructing Line 78, a twin of Line 62.

The current scope of the Line 67 pipeline expansion between Neche, North Dakota and the Superior, Wisconsin Terminal consists of two phases. The initial phase increased capacity from 450,000 Bpd to 570,000 Bpd at an estimated cost of approximately $220 million. The second phase added an additional 230,000 Bpd of capacity at an estimated cost of approximately $240 million. The initial phase was completed in the third quarter of 2014 and the second phase was completed in July 2015. Both phases of the Line 67 pipeline expansion required only the addition of pumping horsepower, with no pipeline construction, and are subject to regulatory and other approvals, including 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. We continue to work with regulatory authorities; however, the timing of the receipt of the amendment to the Presidential border crossing permit to allow for increased flow on the Line 67 pipeline across the border cannot be determined at this time. 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.

In November of 2014 several environmental and Native American groups filed a complaint in the United States District Court in Minnesota against the United States Department of State, or DOS. The Complaint alleges, among other things, that the DOS is in violation of the National Environmental Policy Act by acquiescing in Enbridge’s use of permitted cross border capacity on other lines to achieve the transportation of amounts in excess of Line 67’s current permitted capacity while the review and approval of Enbridge’s application to the DOS to increase Line 67’s permitted cross border capacity is still pending. On December 9, 2015, the District Court ruled that the DOS interpretation of Enbridge’s Presidential permits is not reviewable by a federal court on constitutional grounds.

The current scope of the Southern Access expansion, or Line 61 expansion, between Superior, Wisconsin and Flanagan, Illinois also consists of phases that require only the addition of pumping horsepower with no pipeline construction. The initial phase to increase the capacity from 400,000 Bpd to 560,000 Bpd was completed in August 2014 at a cost of approximately $160 million. We further expanded the pipeline capacity to 800,000 Bpd in May 2015 at an estimated cost of approximately $395 million. Additional tankage is expected to cost approximately $380 million with various completion dates that began in the third quarter of 2015 and are expected to continue through the third quarter of 2016. In the first quarter of 2015, we, in conjunction with shippers, decided to delay the in-service date of a further expansion phase to increase the pipeline capacity to 1,200,000 Bpd to align more closely with the anticipated in-service date for the Sandpiper Project. In October 2015, a portion of this phase was placed into service early to address capacity constraints, increasing pipeline capacity to 950,000 Bpd. The remaining capacity is expected to be placed into service in line with the expected in-service date of the Sandpiper Project.

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Furthermore, as part of the Light Oil Market Access Program, we expanded the capacity on our Lakehead System between Flanagan, Illinois, and Griffith, Indiana by constructing Line 78, a 79-mile, 36-inch diameter twin of Line 62, with an initial capacity of 570,000 Bpd, at an estimated cost of $540 million. Line 78 was placed into service in November 2015.

These projects, collectively referred to as the U.S. Mainline Expansions projects, are expected to cost approximately $2.4 billion. We will operate the 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.

Canadian Eastern Access and Mainline Expansion Projects

The Eastern Access Projects and U.S. Mainline Expansions projects complement Enbridge’s strategic initiative of expanding access to new markets in North America for growing production from western Canada and the Bakken Formation. Since October 2011, Enbridge also announced several complementary Eastern Access and Mainline Expansion Projects, which had various in-service dates throughout 2015. Two of these projects include reversal of Enbridge’s Line 9B from Westover, Ontario to Montreal, Quebec, to serve refineries in Quebec, and an expansion of Enbridge’s Line 9 to provide additional delivery capacity within Ontario and Quebec.

The Line 9B reversal and Line 9 capacity expansion projects were approved by the Canadian National Energy Board, or NEB, in March 2014 subject to 30 conditions. In October 2014, the NEB requested additional information regarding one of the conditions imposed on the Line 9B reversal and Line 9 expansion project. On October 23, 2014, Enbridge responded to the NEB describing Enbridge’s rigorous approach to risk management and isolation valve placement. On February 6, 2015, the NEB approved conditions 16 and 18, the two conditions in the NEB’s order requiring approval, and Enbridge filed for the Leave to Open, or LTO, which is also a prerequisite to allowing the operation of the project. In its February approval, the NEB also imposed additional obligations on Enbridge that directs it to take a “life-cycle” approach to water crossings and valves, requiring Enbridge to perform ongoing analysis to ensure optimal protection of the area’s water resources. On June 18, 2015, the NEB approved the LTO application and issued a separate order imposing further conditions requiring Enbridge to perform hydrostatic tests of selected segments of the pipeline. Enbridge filed its hydrostatic test plan with the NEB on July 23, 2015, which was approved on July 27, 2015. Hydrostatic testing was completed and Enbridge submitted the test results to the NEB in September 2015. On September 30, 2015, the NEB confirmed that the hydrostatic tests successfully met their criteria. Line fill commenced in late October 2015 and the pipeline was placed into service in December 2015.

Enbridge Market Extensions

One of our key strengths is our relationship with Enbridge. In 2014, Enbridge announced the completion of two major U.S. Gulf Coast market access pipeline projects, the Flanagan South Pipeline and Seaway Crude Pipeline, which pull more volume through our pipelines and may lead to further expansions of our Lakehead pipeline system. In 2012, Enbridge announced the Southern Access Extension, which, along with the reversal of Line 9A and Line 9B, will support the increasing supply of light oil from Canada and the Bakken into Patoka, Illinois.

Southern Access Extension

The Southern Access Extension project involves the construction of a 165-mile, 24-inch diameter crude oil pipeline from Flanagan to Patoka, Illinois, with an initial capacity of 300,000 Bpd, as well as additional tankage and two new pump stations. The project was placed into service in December 2015. Lincoln Pipeline LLC, or Lincoln, an affiliate of MPC, has a 35% equity interest in the project and will make additional cash contributions in accordance with the Southern Access Extension’s spend profile in proportion to its 35% interest.

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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 trucking and 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 systems for the years ended December 31, 2015, 2014 and 2013.

		December 31,
		2015				2014				2013
		(in millions)
Operating results:
Operating revenues		$	2,842.7			$	5,894.3			$	5,597.2
Commodity costs			2,372.9				5,145.9				4,948.9
Segment gross margin			469.8				748.4				648.3
Operating expenses:
Operating and administrative			351.0				423.0				449.8
Goodwill impairment			246.7				—				—
Asset impairment			12.3				15.6				—
Depreciation and amortization			157.8				151.4				143.1
Operating expenses			767.8				590.0				592.9
Operating income (loss)			(298.0	)			158.4				55.4
Other income (loss)			29.3				13.2				(1.5	)
Net income (loss)		$	(268.7	)		$	171.6			$	53.9
Operating Statistics (MMBtu/d):
East Texas			964,000				1,030,000				1,153,000
Anadarko			773,000				827,000				949,000
North Texas			265,000				293,000				317,000
Total			2,002,000				2,150,000				2,419,000
NGL Production (Bpd)			81,632				83,675				88,236

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. We performed a goodwill impairment analysis after we learned from customers during the second quarter of 2015 that reductions in drilling will be prolonged in the producing basins in which we operate due to the continued low commodity price environment. As a result of this analysis, we determined that $246.7 million in goodwill was impaired.

Decreases in “Operating revenues” and “Cost of natural gas and natural gas liquids” 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, which 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.

Year ended December 31, 2014, compared with year ended December 31, 2013

The operating income of our Natural Gas segment for the year ended December 31, 2014, increased $103.0 million, as compared with the year ended December 31, 2013. The most significant area affected was segment gross margin, representing revenue less commodity costs, which increased $100.1 million for the year ended December 31, 2014, as compared with the year ended December 31, 2013.

Segment gross margin experienced an increase in non-cash, mark-to-market net gains of $161.5 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily related to non-cash, mark-to-market gains in the year ended December 31, 2014, on our NGL hedges. The values of these hedges and contracts, which help assure the prices we realize on commodities, increased as the related physical commodity value decreased.

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Segment gross margin increased $15.6 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013 due to increased margins from natural gas pricing differentials in 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 from higher than normal demand from winter weather in the Midwest.

Segment gross margin increased $2.3 million for the year ended December 31, 2014, due to improved pricing spreads between our Conway and Mont Belvieu market hubs when compared with the year ended December 31, 2013.

Segment gross margin was affected by reduced production volumes which negatively affected segment gross margin by approximately $45.8 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013. The average daily volumes of our major systems for the year ended December 31, 2014, decreased by approximately 269,000 million British thermal units per day, or MMBtu/d, or 11% when compared to the year ended December 31, 2013. The average NGL production for the year ended December 31, 2014, decreased by 4,561 Bpd, or 5%, when compared to the year ended December 31, 2013. The decrease in natural gas and NGL volumes in the Anadarko region was primarily attributable to the loss in 2013 of a major customer on our Anadarko system and delayed drilling activity by certain producers. The decrease in natural gas volumes in the East Texas region was primarily attributable to reduced dry gas drilling, and delayed drilling activity and well completions.

Segment gross margin derived from keep-whole earnings for the year ended December 31, 2014, decreased $33.4 million when compared to the year ended December 31, 2013, due to a decrease in processing margins primarily driven by lower volumes in keep-whole barrels in the Oklahoma, East Texas, and Anadarko regions.

Segment gross margin decreased approximately $3.0 million for the year ended December 31, 2014, primarily due to the impact of sustained freezing temperatures in the first quarter 2014, which significantly disrupted producer wellhead production levels and our pipeline operations compared to the year ended December 31, 2013.

Operating and administrative costs decreased $26.8 million for the year ended December 31, 2014, when compared to the year ended December 31, 2013 primarily related to reduced outside contract labor, and lower rents and leases. This decrease was offset by an increase in costs from a non-cash impairment on our non-core Louisiana propylene pipeline asset of $15.6 million. The impairment charge was taken following finalization of a contract restructuring with the primary customer. In addition, in December of 2014, the company took actions to reduce its costs through a workforce reduction, which increased severance costs by $4.8 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013.

Depreciation and amortization expense increased $8.3 million, for the year ended December 31, 2014, compared with the year ended December 31, 2013, due to additional assets that were placed into service.

We recognized $13.2 million in equity income in “Other income (expense)” on our consolidated statements of income related to our investment in the Texas Express NGL system. This is due to a full year of operations of the pipeline which went into service in November 2013.

Future Prospects for Natural Gas

We intend to expand our natural gas gathering and processing services by: (1) capturing opportunities within our footprint, (2) expanding outside of our footprint through strategic acquisitions, (3) providing an array of services for both natural gas and NGLs in combination with core asset optimization, and (4) capitalizing on new market opportunities by diversifying geographically and by commodity composition. We will pursue internal growth projects designed to provide exposure to incremental supplies of natural gas at the wellhead, increase opportunities to serve additional customers, including new wholesale customers, and allow expansion of our treating and processing businesses. Additionally, we will pursue acquisitions to expand our natural gas business in situations where we have competitive advantages to create additional value.

Impact of Commodity Prices

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 have remained low throughout 2015. The depressed commodity price environment is the most significant factor for reduced drilling activity and declining volumes in the basins in which we operate. We expect producers to continue to reduce drilling activity due to the current commodity price environment, and as a result, we expect to see a

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decrease in volumes in 2016. We factored these expected decreases into our fixed asset and intangible asset recoverability tests on our Anadarko, North Texas, and East Texas assets during 2015 and do not expect any impairment on these assets at this time. However, further declines in long-term volumes or reserves could affect our assessments.

We have largely mitigated our near-term direct commodity price risk through our hedging program. We have hedged approximately 90% and 40% of our direct forecasted commodity cash flow exposure for 2016 and 2017, respectively. 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 improve as prices improve.

Expansion Projects

The following expansion projects are designed to increase natural gas processing, NGL production, residue gas and NGL transportation capacity. The paragraphs below summarize our projects that we have placed into service in 2015 or expect to place into service in future periods.

Beckville Cryogenic Processing Plant

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 and has been a steady producer of natural gas for decades, as well as the Eaglebine developments. Production from the Cotton Valley formation typically contains two to three gallons of NGLs per Mcf of natural gas. 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 being developed 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. This project cost approximately $165.0 million.

The project was funded by us and MEP based on our proportionate ownership percentages in Midcoast Operating, which are 48.4% and 51.6%, respectively.

Eaglebine Developments

The Eaglebine is an emerging oil play in East Texas that spans over five counties and is comprised of multiple formations, including but not limited to, the Woodbine, Buda, Glenrose and Eagle Ford formations. We have a series of construction projects and an acquisition in this play. We have completed construction of the Ghost Chili pipeline project, which consists of a lateral and associated facilities that create gathering capacity of over 50 MMcf/d for rich natural gas to be delivered from Eaglebine production areas to our complex of cryogenic processing facilities in East Texas. The initial facilities were placed into service in October 2015. We also expect to construct the Ghost Chili Extension Lateral to fully utilize this gathering capacity with the rest of our processing assets when additional development in the basin supports it. Given the proximity of our existing East Texas assets, this expansion into Eaglebine will allow us to offer gathering and processing services while leveraging assets on our existing footprint.

On February 27, 2015, we acquired from New Gulf Resources, LLC, or NGR, its midstream operations in Leon, Madison and Grimes counties, Texas. The acquisition consists of a natural gas gathering system currently in operation. For further details regarding the NGR acquisition, refer to Item 8. Financial Statements and Supplementary Data, Note 4. Acquisitions.

We estimate the aggregate cost of our Eaglebine projects and acquisition described above to be approximately $160.0 million, of which $116.8 million was spent in 2015. Remaining funding is to be provided by us and MEP based on our proportionate ownership percentages in Midcoast Operating, subject to market conditions and our financing capacity.

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Corporate

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

		December 31,
		2015				2014				2013
		(in millions)
Operating Results:
Operating and administrative expenses		$	14.4			$	10.6			$	7.6
Operating loss			(14.4	)			(10.6	)			(7.6	)
Interest expense, net			(322.0	)			(403.2	)			(320.4	)
Allowance for equity used during construction			70.3				57.2				43.1
Other income (expense)			—				(4.3	)			17.5
Income (loss) before income tax expense			(266.1	)			(360.9	)			(267.4	)
Income tax expense			(4.9	)			(9.6	)			(18.7	)
Net loss		$	(271.0	)		$	(370.5	)		$	(286.1	)

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.

Year ended December 31, 2014 compared with year ended December 31, 2013

The increase in our net loss in 2014 was primarily due to an increase in interest expense to $403.2 million for the year ended December 31, 2014, compared with $320.4 million for the corresponding period in 2013. This increase in interest expense is primarily due to an increase of approximately $1.9 billion in our outstanding debt balance. Also contributing to the increase in interest expense is the recognition of unrealized losses for hedge ineffectiveness of approximately $100.1 million.

Income tax expense decreased $9.1 million for the year ended 2014 compared to the same period in 2013, primarily due to a tax law that was passed in June 2013 in the State of Texas, referred to as House Bill 500, or HB 500. The law allows a pipeline company that transports oil, gas, or other petroleum products owned by others to subtract as COGS, its depreciation, operations and maintenance costs related to the services provided. Under the new law, we are allowed additional deductions against our income for Texas margin tax purposes.

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 emphasizes developing and expanding our existing Liquids and Natural Gas businesses through organic growth and targeted acquisitions. 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

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financings will be available on favorable terms, if at all. In addition, we intend to sell additional interests in Midcoast Operating to MEP to raise capital over the course of the next several years. Although this is our intent, there is no assurance that any transactions will occur as they are subject to, among other things, obtaining agreement from MEP and the board of directors of its general partner on the commercial terms of such a sale. In the past, when we had attractive growth opportunities in excess of our own capital raising capabilities, the 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 the 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 $1.975 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 access our $1.5 billion 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.

As set forth in the following table, we had approximately $1.5 billion of liquidity available to us at December 31, 2015, to meet our ongoing operational, investment and financial needs.

		EEP				MEP
		(in millions)
Cash and cash equivalents		$	130.1			$	18.0
Total credit available under our Credit Facilities			2,600.0				—
Total credit available under MEP’s Credit Agreement			—				810.0
Less: Amounts outstanding under our Credit Facilities			1,110.0				—
Less: Amounts outstanding under MEP’s Credit Agreement			—				490.0
Principal amount of commercial paper issuances			326.1				—
Letters of credit outstanding			121.7				—
Total		$	1,172.3			$	338.0

As of December 31, 2015, although we had a working capital deficit of approximately $1.0 billion, we had approximately $1.5 billion of 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 releases on Line 6B.

Capital Resources

Equity and Debt 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. If market conditions change and capital markets become 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.

From time to time, we may seek to satisfy liquidity needs through the issuance of registered debt or equity securities. In February 2015, we filed with the SEC a new shelf registration statement, or the 2015 Shelf, on Form S-3 that replaced our prior shelf registration statement which expired in December 2014. The 2015 Shelf allows us to issue an unlimited amount of equity and debt securities in underwritten public offerings.

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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, 2014 and 2013.

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

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 11. Partners’ Capital.

Midcoast Energy Partner, L.P.

In 2013, MEP completed the Offering of 21,725,000 Class A common units representing limited partner interests, including the underwriter’s over allotment option. MEP received proceeds (net of underwriting discounts, structuring fees and offering expenses) from the Offering of approximately $354.9 million. MEP used the net proceeds to distribute approximately $304.5 million to us, to pay approximately $3.4 million in revolving credit facility origination and commitment fees and used approximately $47.0 million to redeem 2,775,000 Class A common units from us.

On July 1, 2014, we sold a 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which reduced our total ownership interest in Midcoast Operating from 61% to 48.4%. This transaction represents our first sale to MEP of additional interests in Midcoast Operating since the Offering.

At December 31, 2015, 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. We intend to sell additional interests in our natural gas assets, held through Midcoast Operating, to MEP and use the proceeds from any such sale as a source of funding for us. However, we do not know when, or if, any additional interests will be offered for sale.

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Investments

In March and September 2013, Enbridge Management completed public offerings of 10,350,000 and 8,424,686 Listed Shares, respectively, representing limited liability company interests with limited voting rights for net proceeds of $272.9 million and $235.6 million, respectively, Enbridge Management used those proceeds to purchase an equal number of the Partnership’s i-units. We used the proceeds from our sale of i-units to Enbridge Management to finance a portion of our capital expansion program relating to the expansion of our core liquids and natural gas systems and for general corporate purposes.

Credit Facilities

The Credit Facility, permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion, a letter of credit subfacility and a swing line subfacility. 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 is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $625.0 million subject to the terms and conditions set forth therein. The 364-Day Credit Facility provides aggregate lending commitments: (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, which is currently July 1, 2016.

At December 31, 2015, the Credit Facilities provide an aggregate bank credit amount of approximately $2.6 billion, which we use to fund our general activities and working capital needs.

On November 16, 2015, we received a commitment reduction notice from Enbridge (U.S.) Inc., or EUS, an affiliate of Enbridge, with respect to the credit agreement with EUS, or the EUS 364-day Credit Facility, that previously permitted aggregate borrowing of up to, at any one time outstanding, $750.0 million. EUS elected to reduce its commitment to zero following the Partnership’s offering of $1.6 billion of debt securities in October of 2015. See Note 9. Related Party Transactions for further details.

As of December 31, 2015, 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 10. Debt.

We are party to an uncommitted letter of credit arrangement, pursuant to which the bank may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request in an aggregate amount not to exceed $175.0 million. While the letter of credit arrangement is uncommitted and issuance of letters of credit is at the bank’s sole discretion, we view this arrangement as liquidity enhancement as it allows us to potentially reduce our reliance on utilizing the committed Credit Facilities for issuance of letters of credit to support our hedging activities.

Commercial Paper

We are party to a commercial paper program that provides for the issuance of up to an aggregate principal amount of $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. At December 31, 2015, we had $326.1 million in principal amount of commercial paper outstanding at a weighted average interest rate of 1.22%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net repayments of approximately $286.1 million during the year ended December 31, 2015, which includes gross borrowings of $12.0 billion and gross repayments of $12.3 billion. At December 31, 2014, we had $612.3 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.50%, excluding the effect of our interest rate hedging activities. 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. For further details regarding the commercial paper program, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

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The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. It is our policy 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 such time. Taking that policy into account, at December 31, 2015, we could borrow approximately $1.0 billion under the terms of our Credit Facilities, determined as follows:

		(in millions)
Total credit available under our Credit Facilities		$	2,600.0
Less: Amounts outstanding under our Credit Facilities			1,110.0
Principal amount of commercial paper outstanding			326.1
Letters of credit outstanding			121.7
Total amount available at December 31, 2015		$	1,042.2

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 10. 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, our operating subsidiary that owns the Lakehead system, has $200.0 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes. The OLP Notes consist of $100.0 million of 7.000% senior notes due 2018 and $100.0 million of 7.125% senior notes due 2028. 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 10. 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 10. Debt.

MEP Credit Agreement

MEP, Midcoast Operating, and MEP’s material domestic subsidiaries are parties to the MEP Credit Agreement, which is a committed syndicated senior revolving credit facility with related letter of credit and swing line facilities. On September 3, 2015, MEP amended its Credit Agreement to decrease the aggregate commitments to $810.0 million and extend the maturity date from September 30, 2017 to September 30, 2018; however, $140.0 million of commitments will expire on the initial maturity date of November 13, 2016 and an additional $25.0 million of commitments will expire on September 30, 2017.

The MEP Credit Agreement also requires compliance with two financial covenants. MEP is not permitted to allow their 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 must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00. These covenants could limit MEP’s ability to undertake additional debt financing.

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At December, 31, 2015, MEP was in compliance with the terms of our financial covenants in the Credit Agreement. Due to the continued decline in oil and gas prices and the potential implications on their results of operations, it is possible that MEP may not be able to meet the total leverage ratio financial covenant at some point during the remaining term of the facility. If this were to occur, MEP would seek a waiver from its lenders, seek additional capital contributions, pursue refinancing of the amounts outstanding under the Credit Agreement or seek to take other action to prevent a default under the Credit Agreement, although there is no assurance that MEP could obtain any such necessary preventative actions. Failure to comply with one or both of the financial covenants may result in the occurrence of an event of default under the Credit Agreement, which would result in a cross-default under the note purchase agreement on the Notes. If an event of default were to occur, the lenders could, among other things, terminate their commitments under the Credit Agreement, demand immediate payment of all amounts borrowed by MEP and Midcoast Operating, trigger the springing liens, and require adequate security or collateral for all outstanding letters of credit outstanding under the facility.

At December 31, 2015, MEP had $490.0 million in outstanding borrowings under the MEP Credit Agreement at a weighted average interest rate of 3.71%. Under the MEP Credit Agreement, MEP had net borrowings of approximately $130.0 million during the year ended December 31, 2015, which includes gross borrowings of $6.1 billion and gross repayments of $6.0 billion. At December, 31, 2015, MEP was in compliance with the terms of its financial covenants in the MEP Credit Agreement. For further details regarding the MEP Credit Agreement and the amendments thereto, refer to Item 8. Financial Statements and Supplementary Data, under Note 10. Debt.

MEP Private Debt Issuance

In 2014, MEP completed a private offering of $400.0 million of notes consisting of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. All of the Notes pay interest semi-annually on March 31 and September 30, commencing on March 31, 2015.

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

At December 31, 2015, we were in compliance with the terms of our financial covenants under the Notes and the related purchase agreement. Due to the continued decline in oil and gas prices and the potential implications on our results of operations, it is possible that we may not be able to meet the total leverage ratio financial covenant at some point during the remaining term of the facility. If this were to occur, we would seek a waiver from the note holders, seek additional capital contributions, pursue refinancing of the amounts outstanding under the Notes or seek to take other action to prevent a default under the purchase agreement and the Notes, although there is no assurance that we could obtain any such necessary preventative actions. Any failure to comply with one or both of the financial covenants could result in the occurrence of an event of default under the purchase agreement and the Notes and result in a cross-default under the Credit Agreement. If an event of default were to occur, the note holders could, among other things, demand immediate payment of the Notes and trigger the springing liens.

For further details about the Notes and related private placement, refer to Item 8. Financial Statements and Supplementary Data, under Note 10. Debt.

Maturities of Third Party Debt

The scheduled maturities of outstanding third-party debt, excluding any discounts at December 31, 2015, are summarized as follows in millions:

2016			300.0
2017			826.1
2018			990.0
2019			575.0
2020		$	1,610.0
Thereafter			3,775.0
Total		$	8,076.1

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Joint Funding Arrangements

In order to obtain the required capital to expand our various pipeline systems, we have determined that the required funding would challenge our ability to efficiently raise capital. Accordingly, we have explored numerous options and determined that several joint funding arrangements would provide the best source of available capital to fund the expansion projects.

Joint Funding Arrangement for Alberta Clipper Pipeline

Until January 2, 2015, we had a joint funding arrangement with several of our affiliates and affiliates of Enbridge to finance the construction of the United States segment of the Alberta Clipper Pipeline. On January 2, 2015, we completed the Drop Down transaction pursuant to which the General Partner and its affiliates contributed to us the remaining 66.7% interest in the U.S. segment of the Alberta Clipper Pipeline in exchange for approximately 18,114,975 units of a new class of limited partner interests designated as Class E units with a fair value of $767.7 million. As part of the joint funding arrangement, we repaid borrowings outstanding and payable to our General Partner under a promissory note, which we referred to as the A1 Term Note.

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 will temporarily forego Series EA and ME, collectively, the Series, distributions commencing in the quarter ended June 30, 2015, through the quarter ending March 31, 2016. The General Partner’s capital funding contribution requirements for each of those two Series, commencing in August 2015, will be reduced by the amount of its foregone cash distributions from the respective Series, until the earlier of December 31, 2016 and the date aggregate reductions in capital contributions for such Series are equal to the foregone cash distributions for such Series. To the extent that the General Partner’s portion of capital contributions prior to December 31, 2016 are insufficient to cover the General Partner’s foregone cash distributions for a Series, beginning with the distribution related to the first quarter of 2017 for that Series, we will receive reduced cash distributions by up to 50%, and the General Partner will receive a comparable increase in cash distributions each quarter until the General Partner has received an aggregate amount of contribution reductions and distribution increases equal to the amount of foregone cash distributions.

Joint Funding Arrangement for Eastern Access Projects

We have a joint funding arrangement with the General Partner that establishes an additional series of partnership interests in the OLP, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. Our General Partner owns 75% of the EA interests, and, except as described above in Amendment of OLP Limited Partnership Agreement, the Eastern Access Projects are jointly funded by our General Partner at 75% and us at 25%. Within one year of the in-service date, scheduled for mid-2016, we have the option to increase our economic interest by up to 15 percentage points. During 2015, the General Partner made equity contributions of $119.3 million to the OLP to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Joint Funding Arrangement for U.S. Mainline Expansion Projects

We have a joint funding arrangement with the General Partner that establishes another series of partnership interests in the OLP, which we refer to as the ME interests. The ME interests were created to finance 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, which we refer to as our Mainline Expansion Projects. Our General Partner now owns 75% of the ME interests, and, except as described above in Amendment of OLP Limited Partnership Agreement, the U.S. Mainline Expansion Projects are jointly funded by our General Partner at 75% and us at 25%. Within one year of the in-service date, currently scheduled for 2016, we have the option to increase our economic interest held at that time by up to 15 percentage points. During 2015, the General Partner made equity contributions of $673.3 million to the OLP to fund its equity portion of the construction costs associated with the U.S. 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 12. Related Party Transactions.

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Sale of Accounts Receivable

We and certain of our subsidiaries are parties to a receivables purchase agreement, which we refer to as the Receivables Agreement, with an indirect wholly owned subsidiary of Enbridge. The Receivables Agreement terminates on December 30, 2016. 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.

For the year ended December 31, 2015, we sold and derecognized $3,710.4 million of receivables to the Enbridge subsidiary, and we received cash proceeds of $3,709.3 million. As of December 31, 2015, $317.0 million of the receivables were outstanding and had not been collected on behalf of the Enbridge subsidiary.

For further details regarding the Receivable Agreement, refer to Item 8. Financial Statements and Supplementary Data, under Note 12. Related Party Transactions.

Cash Requirements

Capital Spending

We incurred capital expenditures of approximately $2.2 billion for the year ended December 31, 2015, including $93.2 million of maintenance capital expenditures and $863.3 million of expenditures that were financed by contributions from our General Partner and MPC via joint funding arrangements. In addition, we incurred $4.2 million of contributions to fund our joint ventures. At December 31, 2015, we had approximately $678.6 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.

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 our Credit Facility, 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.

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 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.

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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. Due to the completion of major projects, and lower-than-anticipated spending on the Sandpiper and Line 3 Replacement projects in 2016, we expect our expansion capital expenditures to be significantly lower in 2016 than in recent years. The following table sets forth our estimated maintenance and expansion capital expenditures of $900.0 million for the year ending December 31, 2016. We expect to receive funding of approximately $430.0 million from our General Partner based on our joint funding arrangement for the Eastern Access Projects and Mainline Expansion Projects. Furthermore, we expect to receive funding of approximately $55.0 million from MPC based on our joint funding arrangement for the Sandpiper Project. Although we anticipate making these expenditures in 2016, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, 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		$	215
U.S. Mainline Expansions			360
Sandpiper			140
Line 3 Replacement			185
Liquids Integrity Program			280
Expansion Capital			100
Maintenance Capital Expenditures			60
			1,340
Less joint funding from:
General Partner(2)			430
Third parties			55
Liquids Total		$	855
Natural Gas Projects
Expansion Capital		$	50
Maintenance Capital Expenditures			40
			90
Less joint funding from:
MEP			45
Natural Gas Total		$	45
TOTAL		$	900

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.”

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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 our operations and to finance a portion of our capital expansion projects. During 2015, we distributed a total of 4,980,552 i-units through quarterly distributions to Enbridge Management, compared with 4,562,088 and 3,769,989 in 2014 and 2013, respectively.

The following table represents cash we have retained in our business since January 2013 from the in-kind distribution of additional i-units:

Distribution Payment Date		Retained for i-units				Retained from General Partner				Total Cash Retained
		(in millions)
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				0.7				37.4
May 15			35.3				0.7				36.0
February 14			34.6				0.7				35.3
		$	143.9			$	2.9			$	146.8
2013
November 14		$	34.1			$	0.7			$	34.8
August 14			28.9				0.6				29.5
May 15			28.4				0.6				29.0
February 14			22.4				0.4				22.8
		$	113.8			$	2.3			$	116.1

Our current annual cash distribution rate is $2.332 per unit, or $0.58300 per quarter, for the year ended December 31, 2015, compared with $2.22 per unit, or $0.55500 per quarter, for the year ended December 31, 2014. We expect that all cash distributions will be paid out of operating cash flows over the long term. However, from time to time, we may temporarily borrow under our Credit Facilities or use cash retained by issuance of payment in-kind distributions for the purpose of paying cash distributions. We may do this until we realize the full impact of assets being developed on operations or to respond to short-term aberrations in our performance caused by market disruption events or depressed commodity prices. As various projects are under construction, we expect our coverage ratio to weaken as assets under construction do not generate cash flow until they enter service and we are bearing the related financial costs. We expect that our major capital expansion projects will be accretive to distributable cash flow when they are operational and the coverage ratio to then improve. Long term sustainability

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of our distributions is a key focus of the management assigned to oversee our operation. Increases in our distribution rate are made when expected to be sustainable for the long-term and upon the approval of the Board of Directors of Enbridge Management.

Series AC Distributions

For periods prior to our purchase of the remaining 66.7% interest in the U.S. portion of the Alberta Clipper Pipeline, the OLP was required to pay a quarterly distribution, also referred to as the Series AC distribution amount, within 45 days of the end of each calendar quarter to the holders of the Series AC general and limited partner interests under the terms of the then OLP partnership agreement, consisting of the sum of: (1) the portion of the Series AC revenue entitlement that was collected during the quarter through the transportation rates of our Lakehead system, (2) any other cash receipts attributable to the Series AC assets collected during the quarter, and (3) any reduction during the quarter in the amount of the Series AC reserves established in any prior quarter that are not utilized by the OLP, less the sum of: (a) all cash expenses related to the Series AC assets for the quarter, (b) all cash interest expenses and principal reductions of net borrowings for the quarter attributable to Series AC liabilities, (c) any cash maintenance and pipeline integrity capital expenditures for the quarter that are properly allocable to the Series AC assets, (d) any other cash expenses for the quarter attributable to Series AC liabilities, and (e) any increase in Series AC reserves established to provide for the proper conduct of the business of the Series AC interests.

The following table presents distributions by the OLP for the years ended December 31, 2015, 2014, and 2013, to our General Partner and its affiliate, representing the noncontrolling interest in the Series AC, and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests and pursuant to the OLP’s partnership agreement. Pursuant to the OLP’s partnership agreement, the final ownership distribution for the Series AC interests was distributed to Series AC partners of record as of the last day of the fourth quarter of 2014.

Distribution Declaration Date		Distribution Payment Date				Amount Paid to Partnership				Amount Paid to the noncontrolling interest				Total Series AC Distribution
										(in millions)
2015
January 29			February 13			$	13.7			$	27.5			$	41.2
2014
October 31			November 14			$	10.1			$	20.3			$	30.4
July 31			August 14				7.4				14.8				22.2
April 30			May 15				6.6				13.1				19.7
January 30			February 14				6.4				12.8				19.2
						$	30.5			$	61.0			$	91.5
2013
October 31			November 14			$	7.0			$	14.1			$	21.1
July 29			August 14				5.5				11.0				16.5
April 30			May 15				7.5				14.9				22.4
January 30			February 14				6.9				13.8				20.7
						$	26.9			$	53.8			$	80.7