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 1-36175

 

MIDCOAST ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware		61-1714064
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1100 Louisiana Street, Suite 3300, Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

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

 

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

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

 

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

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 o		Accelerated Filer                     x
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 $225,232,377.

As of February 12, 2016, the registrant has 22,610,056 Class A common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			15
Item 2. Properties			41
Item 3. Legal Proceedings			42
Item 4. Mine Safety Disclosures			42
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of   Equity Securities			43
Item 6. Selected Financial Data			44
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			45
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			67
Item 8. Financial Statements and Supplementary Data			69
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			121
Item 9A. Controls and Procedures			121
Item 9B. Other Information			122
PART III
Item 10. Directors, Executive Officers and Corporate Governance			123
Item 11. Executive Compensation			129
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder   Matters			150
Item 13. Certain Relationships and Related Transactions, and Director Independence			152
Item 14. Principal Accountant Fees and Services			153
PART IV
Item 15. Exhibits and Financial Statement Schedules			154
Signatures			155

In this report unless the context otherwise requires, references in this report to “the Predecessor,” “we,” “our,” “us,” or like terms, when used in a historical context (before November 13, 2013), refer to Midcoast Operating, L.P. References in this report to “Midcoast Energy Partners,” “the Partnership,” “MEP,” “we,” “our,” “us,” or like terms used in the present tense or prospectively (on and after November 13, 2013) refer to Midcoast Energy Partners, L.P. and its subsidiaries. We refer to our general partner, Midcoast Holdings, L.L.C., as our “General Partner” and to Enbridge Energy Partners, L.P. and its subsidiaries, other than us, as “Enbridge Energy Partners,” or “EEP.” References to “Enbridge” refer collectively to Enbridge Inc. and its subsidiaries other than us, our subsidiaries, our General Partner, EEP, its subsidiaries and its general partner. References to “Enbridge Management” refer to Enbridge Energy Management, L.L.C., the delegate of EEP’s general partner that manages EEP’s business and affairs. References to “Midcoast Operating” refer to Midcoast Operating, L.P. and its subsidiaries. After the closing of our initial public offering on November 13, 2013, we owned a 39% controlling interest in Midcoast Operating, and EEP owned a 61% noncontrolling interest in Midcoast Operating; however, on July 1, 2014, we acquired an additional 12.6% interest in Midcoast Operating from EEP. As of December 31, 2015 the ownership percentages for us and EEP were 51.6% and 48.4%, respectively. Unless otherwise specifically noted, financial results and operating data are shown on a 100% basis and are not adjusted to reflect EEP’s noncontrolling interest in Midcoast Operating.

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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 natural gas, natural gas liquids, or NGLs, and crude oil, and the response by natural gas and crude oil producers to changes in any of these factors; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline and gathering systems, as well as other processing and treating plants; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (5) hazards and operating risks that may not be covered fully by insurance; (6) changes in or challenges to our rates; (7) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (8) cost overruns and delays on construction projects resulting from numerous factors.

For additional factors that may affect results, see “Item-1A. Risk Factors” included elsewhere in this Annual Report on Form 10-K, our subsequently filed Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K which are available to the public over the Internet at the United States Securities and Exchange Commission’s, or the SEC’s, website (www.sec.gov) and at our website (www.midcoastpartners.com).

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Glossary

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

Anadarko system			Natural gas gathering and processing assets located in western Oklahoma and the Texas panhandle which serve the Anadarko basin, inclusive of the Elk City system
AOCI			Accumulated other comprehensive income
APSA			Accountable Pipeline Safety and Partnership Act of 1996
Bbl			Barrel of liquids (approximately 42 United States gallons)
Bpd			Barrels per day
CAA			Clean Air Act
CERCLA			Comprehensive Environmental Response, Compensation, and Liability Act
CFTC			Commodity Futures Trading Commission
CWA			Clean Water Act
Dodd-Frank Act			Dodd-Frank Wall Street Reform and Consumer Protection Act
DOT			United States Department of Transportation
East Texas system			Natural gas gathering, treating and processing assets in East Texas that serve the Bossier trend and Haynesville shale areas, also includes a system formerly known as the Northeast Texas system
EBITDA			Earnings before Interest, Taxes, Depreciation and Amortization
EEP			Enbridge Energy Partners, L.P. and its subsidiaries other than Midcoast Energy Partners, L.P. and its subsidiaries
Enbridge			Enbridge Inc., of Calgary, Alberta, Canada, the ultimate parent of the General Partner
Enbridge Management			Enbridge Energy Management, L.L.C.
EP Act			Energy Policy Act of 1992
EPA			Environmental Protection Agency
EPS			Earnings Per Share
Exchange Act			Securities Exchange Act of 1934, as amended
FERC			Federal Energy Regulatory Commission
General Partner			Midcoast Holdings, L.L.C., the general partner of the Partnership
GHG PSD			Greenhouse Gas Prevention of Significant Deterioration
GPP			Gas Pipelines and Processing
HB 500			House Bill 500
HCA			High consequence area
HCDP Plants			Hydrocarbon dewpoint control facilities
HLPSA			Hazardous Liquid Pipeline Safety Act of 1979
ICA			Interstate Commerce Act
IRA			Individual retirement accounts
ISDA®			International Swaps and Derivatives Association, Inc.
LIBOR			London Interbank Offered Rate — British Bankers’ Association’s average settlement rate for deposits in United States dollars
MEP			Midcoast Energy Partners, L.P. and its consolidated subsidiaries
MIC			Enbridge Management Information Circular
MLP			Master Limited Partnership
MMBbls			Million barrels of liquids
MMBtu/d			Million British Thermal units per day
MMcf/d			Million cubic feet per day
NAAQs			National Ambient Air Quality Standards
NESHAP			National Emission Standards for Hazardous Air Pollutant
NGA			Natural Gas Act of 1938
NGLs			Natural gas liquids
NGPA			Natural Gas Policy Act of 1978

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NGPSA			Natural Gas Pipeline Safety Act of 1968
NGR			New Gulf Resource, LLC
North Texas system			Natural gas gathering and processing assets located in the Fort Worth basin serving the Barnett Shale area
NPNS			Normal purchases and normal sales
NSPS			New Source Performance Standards
NYSE			New York Stock Exchange
OCC			Oklahoma Corporation Commission
Offering			MEP initial public offering
OLP			Enbridge Energy, Limited Partnership
OPA			Oil Pollution Act
Partnership Agreement			First Amended and Restated Agreement of Limited Partnership of Midcoast Energy Partners, L.P., also referred to as our partnership agreement
Partnership			Midcoast Energy Partners, L.P. and its consolidated subsidiaries
PHMSA			Pipeline and Hazardous Materials Safety Administration
PIPES			Pipeline Inspection, Protection, Enforcement and Safety Act of 2006
Ppb			Parts per billion
PSA			Pipeline Safety Act of 1992
PSIA			Pipeline Safety Improvement Act of 2002
SEC			United States Securities and Exchange Commission
Texas Express NGL system			NGL gathering system and an NGL interstate mainline transportation pipeline that originates in Skellytown, Texas, and extends to NGL fractionation and storage facilities located in Mont Belvieu, Texas
TRI			Toxic Release Inventory
TRRC			Texas Railroad Commission
TSX			Toronto Stock Exchange
U.S. GAAP			United States Generally Accepted Accounting Principles
WOTUS			Waters of the United States

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PART I

Item 1. Business

OVERVIEW

We are a publicly traded Delaware limited partnership formed in 2013 by EEP to serve as EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. As a pure-play U.S. natural gas and NGL midstream business, we are able to pursue a focused and flexible strategy and have the opportunity to grow through organic growth opportunities and acquisitions, including potential additional drop-down transactions from EEP. Our Class A common units are traded on the New York Stock Exchange, or NYSE, under the symbol “MEP.”

After the closing of our initial public offering in November 2013, or the Offering, we owned a 39% controlling interest in Midcoast Operating, and EEP owned a 61% noncontrolling interest in Midcoast Operating. On July 1, 2014, EEP sold an additional 12.6% limited partner interest in Midcoast Operating to us, which reduced EEP’s total ownership interest in Midcoast Operating from 61% to 48.4% and increased our ownership from 39% to 51.6%. Unless otherwise specifically noted, financial results and operating data are shown on a 100% basis and are not adjusted to reflect EEP’s 61% noncontrolling interest in Midcoast Operating through June 30, 2014, and EEP’s 48.4% noncontrolling interest in Midcoast Operating after June 30, 2014.

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The following chart shows our organization and ownership structure as of December 31, 2015. The ownership percentages set forth below illustrate the relationships among us, Midcoast Operating, our General Partner, EEP, Enbridge and its affiliates; such ownership interests may be held directly or indirectly:

We own a 51.6% limited partner interest in Midcoast Operating, a Texas limited partnership that owns a network of natural gas and NGL gathering and transportation systems, natural gas processing and treating facilities and NGL fractionation facilities primarily located in Texas and Oklahoma. We also own 100% of Midcoast Operating’s general partner. Midcoast Operating also owns and operates natural gas, condensate and NGL logistics and marketing assets that primarily support its gathering, processing and transportation business. Through our ownership of Midcoast Operating’s general partner, we control, manage and operate these systems.

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Our business primarily consists of gathering unprocessed and untreated natural gas from wellhead locations and other receipt points on our systems, processing the natural gas to remove NGLs and impurities at our processing and treating facilities and transporting the processed natural gas and NGLs to intrastate and interstate pipelines for transportation to various customers and market outlets. In addition we also provide marketing services of natural gas and NGLs to wholesale customers.

We seek to provide our customers with quality field-level service and responsiveness using our strong platform of natural gas and NGL infrastructure. We are able to provide our customers with integrated wellhead-to-market service from our systems to major energy market hubs in the Gulf Coast and Mid-Continent regions of the United States. From these market hubs, natural gas and NGLs are either consumed in local markets or transported to consumers in the midwest, northeast and southeast United States.

BUSINESS STRATEGY

Our principal financial objective is to increase the amount of cash distributions we make to our unitholders over time while maintaining our focus on safety and stability in our business. Our plan for executing this objective includes the following business strategies:

We are committed to maintaining and continually improving the safety, reliability and efficiency of our operations, which we believe is key to attracting new customers and maintaining relationships with our current customers, regulators and the communities in which we operate. We strive for operational excellence by utilizing robust programs to integrate environmental integrity, health and occupational safety and risk management principles throughout our business. We employ comprehensive integrity management, inspection, monitoring and audit initiatives in support of this strategy.

To address the increasing producer focus on the liquids portion of the midstream natural gas value chain, we expect to continue to increase our natural gas processing capacity, NGL takeaway capacity options, and our third-party fractionation alternatives, which we believe will, over the long-term, increase the attractiveness and profitability of our natural gas and NGL systems, attract new customers and increase our business with existing customers. We seek to capitalize on opportunities to attract new customers, increase volumes of natural gas and NGLs that we gather, process or treat, transport and otherwise enhance utilization and operating efficiencies, including increasing customer access to preferred natural gas and NGL markets. We are committed to increase our percentage of fee-based contracts to reduce commodity exposure and further strengthen our profitability. We believe our approach provides our customers with greater value for their commodities and increases the utilization of our natural gas and NGL systems.

We intend to maintain a balanced capital structure that should afford us access to the capital markets at a competitive cost of capital. Although we do not currently have a credit rating, we plan to target debt-to-EBITDA, EBITDA-to-interest and other key credit metrics that are consistent with investment grade rated businesses in our industry. We intend to finance long-term growth projects and acquisitions with a balanced combination of debt and equity that we believe will, together with our balanced capital structure, promote the long-term stability of our business.

We seek out attractive organic expansion and asset enhancement opportunities that leverage our existing asset footprint, strategic relationships with our customers and our expertise in constructing, developing and optimizing midstream infrastructure assets. The organic development projects we pursue are designed to extend our geographic reach, diversify our customer base, expand our gathering systems and our processing and treating capacity, enhance end-market access and maximize throughput volumes. For more information relating to growth opportunities refer to Business Segments.

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We intend to pursue acquisitions of additional interests in Midcoast Operating from EEP, as well as accretive acquisitions from third parties that complement or diversify our existing operations. EEP has indicated that it intends to offer us the opportunity to purchase additional interests in Midcoast Operating from time to time, although EEP is not legally obligated to do so. We do not know when or if any such additional interests will be offered to us to purchase.

BUSINESS SEGMENTS

We conduct our business through two distinct reporting segments: Gathering, Processing and Transportation and Logistics and Marketing.

These segments have unique business activities that require different operating strategies. For information relating to revenues from third-party customers, operating income and total assets for each segment, refer to Part II, Item 8. Financial Statements and Supplementary Data, Note 18. Segment Information.

Gathering, Processing and Transportation

Our gathering, processing and transportation business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. We gather natural gas from the wellhead and central receipt points on our systems, deliver it to our facilities for processing and treating and deliver the residue gas to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies. We deliver the NGLs produced at our processing and fractionation facilities to intrastate and interstate pipelines for transportation to the NGL market hubs in Mont Belvieu, Texas and Conway, Kansas. In addition, we deliver NGLs from certain of our facilities to the Texas Express NGL system for transportation on the Texas Express NGL mainline to Mont Belvieu, Texas.

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

		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)			—				—				—				—

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.

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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. Since the third quarter of 2015, a portion of our owned NGLs is sold directly to a third-party, while the remainder, including condensate, is sold to our logistics and marketing business. The NGLs produced at our Anadarko system processing plants are transported by pipeline to third-party fractionation facilities and NGL market hubs in Conway, Kansas and Mont Belvieu, Texas.

East Texas System

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 New Gulf Resources, LLC, or 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 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 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. Since the third quarter of 2015, all of our owned residue gas is now sold directly to third-party wholesale customers or utilities, whereas a majority was previously sold to our Logistics and Marketing segment. Our owned condensate is sold to our logistics and marketing business. A portion of the NGLs produced at one of our East Texas system processing plants is fractionated by us and sold directly to a third-party chemical company. The remainder of the NGLs recovered at our plants are sold to our logistics and marketing business and transported by pipeline to Mont Belvieu, Texas for fractionation.

North Texas System

A substantial portion of natural gas on our North Texas system is produced in the Barnett Shale play within the Fort Worth basin. The North Texas wells are located in the Fort Worth basin and generally have long lives with predictable flow rates. As producers have shifted 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

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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 logistics and marketing business. Since the third quarter of 2015, our owned residue gas is now directly sold to third parties, whereas it was previously sold to our Logistics and Marketing segment.

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

Supply and Demand.  Demand for our gathering, processing and transportation services primarily depends upon the supply of natural gas reserves and associated natural gas from crude oil development and the drilling rate for new wells. The level of impurities in the natural gas gathered also affects treating services. All of our gathering, processing and transportation systems exist in regions that have shale or tight sands formations where 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 gathering, processing and transportation business is significant in all of the markets we serve. Competitors include interstate and intrastate pipelines or their affiliates and other midstream businesses that gather, treat, process and market natural gas or NGLs. Our gathering business’s principal competitors are other midstream companies and, to a lesser extent, producer-owned gathering systems. Some of these competitors are substantially larger than we are. Because pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipeline companies. Pipelines typically compete with each other based on location, capacity, reputation, price and reliability.

Competition for the services we provide varies based upon the location of gathering, treating and processing facilities. Most upstream customers have alternate gathering, treating and processing facilities available to them. In addition, they have alternatives such as building their own gathering facilities or, in some cases, selling their natural gas supplies without treating and processing. On sour natural gas systems, such as parts of our East Texas system, competition is more limited in certain locations due to the infrastructure required to treat sour natural gas. Many of the large wholesale customers we serve have multiple pipelines connected or adjacent to their facilities. Accordingly, many of these customers have the ability to purchase natural gas directly from a number of pipelines or third parties that may hold capacity on the various pipelines. In addition, several new interstate natural gas pipelines have been and are being constructed in areas currently served by our natural gas transportation pipelines. Some of these new pipelines may compete for customers with our existing pipelines.

Logistics and Marketing

The primary role of our logistics and marketing business is to provide marketing services of natural gas, NGLs and condensate received from our gathering, processing and transportation business. We purchase and receive natural gas, NGLs and other products from pipeline systems and processing plants and sell and deliver them to

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wholesale customers, such as distributors, refiners, fractionators, chemical facilities, various third parties and end users. Our Logistics and Marketing segment derives a majority of its operating income from selling natural gas, NGLs and condensate received from producers on our Gathering, Processing and Transportation segment pipeline assets. A majority of the natural gas and NGLs we purchase are produced in Texas markets where we have intrastate deliverability alternatives over the past several years. We use our connectivity to interstate pipelines to improve value for the producers by delivering natural gas into premium markets and NGLs to primary markets where we sell them to major customers. Additionally, our Logistics and Marketing segment derives operating income from providing logistics services for our customers from the wellhead to markets.

On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Logistics and Marketing segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third party. Since that date, Midcoast Operating subsidiaries sell natural gas products directly to third parties, instead of through the Logistics and Marketing segment, which has seen reduced activity related to the sale of natural gas as a result of that transaction.

The physical assets of our logistics 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 logistics and marketing services we provide to our gathering, processing and transportation business and to third-party customers. These agreements provide our logistics and marketing business with the following:

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

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

Since major market hubs for NGLs and related products are located in the Mid-Continent and Gulf Coast regions of the United States and our logistics and marketing business assets are geographically located within Texas, Louisiana, Oklahoma, Kansas and Mississippi, the majority of activities conducted by our logistics and marketing business are conducted within those states. Our interconnected gathering and transportation systems and our 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 logistics and marketing business is our natural gas and NGL purchase and resale activities. Through our natural gas and NGL purchase and resale services, we can efficiently manage the transportation and delivery of natural gas from our gathering, processing and transportation assets and deliver them to on-system industrial customers, and NGLs to marketing companies at various market hubs. We typically price our

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sales based on multiple published daily or monthly price indices. In addition, sales to wholesale customers include a pass-through charge for costs of transportation and additional margin to compensate us for the associated services we provide.

Our logistics and marketing business also uses 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 logistics and marketing business has 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 of Intrastate Natural Gas Pipelines

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

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

Regulation by the FERC of Intrastate Natural Gas Pipelines

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

Natural Gas Gathering Regulation

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from the jurisdiction of the FERC. We own certain natural gas facilities that we believe meet traditional tests the FERC has used to establish a facility’s status as a gatherer not subject to FERC jurisdiction. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are subject to certain reporting requirements resulting from the FERC Order 704 series.

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

NGL Pipeline Regulation

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

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

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

Sales of Natural Gas, Condensate and Natural Gas Liquids

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

Our sales of condensate and NGLs currently are not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC’s 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.

Safety Regulation and Environmental

General

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

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Pipeline Safety and Transportation Regulation

Some of our natural gas pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002, or PSIA, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transmission pipelines in high-consequence areas, or HCAs. HCAs are defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management.

Our NGL pipelines are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979, or the HLPSA, and the Pipeline Safety Act of 1992, or the PSA. The HLPSA requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline. The PSA added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs.

Our pipelines are also subject to the Accountable Pipeline Safety and Partnership Act of 1996, or the APSA, which limited the operator identification requirement to operators of pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel.

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

Although many of our pipeline facilities are not classified as transmission pipelines and currently are not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our transmission pipelines on an annual basis as required by existing United States Department of Transportation, or DOT, regulations and their state counterparts. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that we expand our integrity management program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on our operations.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs.

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The PHMSA finalized a rule increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. The PHMSA also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. The PHMSA has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. The PHMSA also has published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrostatic tests of our facilities to confirm the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending through more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

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

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

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

We believe that our pipeline, 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.

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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 VOC, 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 update the original 2012 standard 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 them 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

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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 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, our General Partner could also be liable for such costs to the extent that we are unable to fulfill our obligations. We have conducted site investigations at some of our facilities to assess historical environmental issues, and we are currently addressing soil and groundwater contamination at various facilities through remediation and monitoring programs, with oversight by the applicable governmental agencies where appropriate.

EMPLOYEES

We are managed and operated by the board of directors and executive officers of our General Partner. Neither we nor our subsidiaries have any employees. Affiliates of our General Partner provide the employees and other personnel necessary to conduct our operations. We believe that our General Partner and its affiliates have a satisfactory relationship with those employees.

INSURANCE

Our operations are subject to many hazards inherent in the midstream industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We are insured under the comprehensive insurance program that is maintained by Enbridge for its subsidiaries. The policy includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and has a renewal date of May 1, 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 EEP, Enbridge and other Enbridge subsidiaries.

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The insurance policy coverage limits and deductible amounts at December 31, 2015, for Enbridge, Inc. and its subsidiaries are:

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

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Item 1A. Risk Factors

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

Risks Related to our Business

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

We may not generate sufficient distributable cash flow each quarter to support the payment of the targeted minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

In addition, the actual amount of distributable cash flow we generate will also depend on other factors, some of which are beyond our control, including:

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Our financial performance could be adversely affected if our assets are used less. Any decrease in the volumes of natural gas or NGLs that we gather or transport or in the volumes of natural gas that we process and treat, or NGLs that we fractionate, could adversely affect our financial condition, results of operations and cash flows.

Our financial performance depends to a large extent on the volumes of natural gas and NGLs processed, treated, fractionated and transported on our systems. Decreases in the volumes processed, treated, fractionated and transported by our systems can directly and adversely affect our revenues and results of operations. These volumes can be influenced by factors beyond our control, including:

The volumes of natural gas and NGLs processed, treated, fractionated and transported on our systems also depends on the supply of natural gas, NGLs, and condensate from the producing regions that supply these systems. Supply of natural gas and NGLs can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on our systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (1) the level of successful drilling activity in our areas of operation, (2) our ability to compete for volumes from successful new wells and (3) our ability to compete successfully for volumes from sources connected to other pipelines. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment. In addition, existing customers may not extend their contracts for a variety of reasons, including a decline in the availability of natural gas from the Mid-Continent, United States Gulf Coast and East Texas producing regions or if the cost of transporting natural gas from other producing regions through other pipelines into the markets served by our systems were to render the delivered cost of natural gas or NGLs on our systems uneconomical. If we are unable to find additional customers to replace lost demand or transportation fees, or if we are unable to find new sources of supply to maintain the current levels of throughput on our systems, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders could be materially and adversely affected.

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Natural gas and liquid hydrocarbon prices are volatile, and a change in these prices in absolute terms, or an adverse change in the prices of natural gas and liquid hydrocarbons relative to one another, could adversely affect our total segment margin and cash flow and our ability to make cash distributions to our unitholders.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. The prices of natural gas, liquid hydrocarbons and other commodities have been extremely volatile, and we expect this volatility to continue. Our future cash flow may be materially adversely affected if we experience significant, prolonged pricing deterioration. For example, if there is a significant change in the relative prices of NGLs, condensate, crude oil, and/or natural gas, it will impact our processing margins, which are a significant component of our ability to generate cash for distribution to our unitholders.

The markets for and prices of natural gas, liquid hydrocarbons and other commodities depend on factors that are beyond our control. These factors include the supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

Margins we would have realized from processing activities under certain of our percentage-of-liquids contracts may be reduced if we are unable to process a portion of the natural gas under these contracts.

Under certain of our percentage-of-liquids contracts, we have guaranteed a fixed recovery of NGLs to our customers. To the extent that the volumes of natural gas delivered to us exceed the processing capacity of our processing plants, we may have to pay those customers the fully processed value of their natural gas even though we were unable to process a portion of their natural gas due to capacity limitations, which could reduce the margins we would have otherwise realized from processing activities under these contracts.

Commodity price volatility and risks associated with our hedging activities could adversely affect our cash flow and our ability to make cash distributions to our unitholders.

Our industry remains in a weak commodity price cycle, which could extend beyond 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 direct commodity price exposure in 2016. We employ 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, we may be prevented from realizing the full benefits of price increases above the level of the hedges. However, because we are not fully hedged, we will continue to have commodity price exposure on the unhedged portion of the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of this unhedged exposure, a substantial decline in the prices of these commodities could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

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

Competition may materially and adversely affect our business and results of operations.

We face competition in our gathering, processing and transportation business, as well as in our marketing and logistics business. Some of our competitors are larger companies that have greater financial, managerial and other resources than we do. Our competitors may expand or construct gathering, processing or transportation systems that would create additional competition for the services we provide to our customers. In addition, many of the large wholesale customers served by our natural gas systems have multiple pipelines connected or adjacent to their facilities. Thus, many of these wholesale customers have the ability to purchase natural gas directly from a number of pipelines or from third parties that may hold capacity on other pipelines. Most natural gas producers and owners have alternate gathering and processing facilities available to them. In addition, they have other alternatives, such as building their own gathering facilities or, in some cases, selling their natural gas supplies without processing. Some of our natural gas and NGL marketing competitors have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do. All of these competitive factors could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

If we fail to balance our purchases of natural gas and our sales of residue gas and NGLs, our exposure to commodity price risk will increase.

We may not be successful in balancing our purchases of natural gas and our sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

Our natural gas assets are primarily located in Texas and Oklahoma. Due to our lack of geographic diversification, adverse developments in our existing areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

Our natural gas assets are primarily located in Texas and Oklahoma and we intend to focus our future capital expenditures largely on developing our business in these areas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of geographic diversity, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders than if our operations were more diversified.

Future construction and development costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate, which may limit our ability to make cash distributions to our unitholders.

Our strategy to grow our business contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets. The construction of new assets involves numerous regulatory, environmental, legal, political, materials and labor cost and operational risks that are difficult to predict and beyond our control. As a result, we may not be able to complete our projects at the costs estimated or within the time periods we have projected. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:

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Any or all of these methods may not be available when or in the amounts needed or may adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Our revenues and cash flows may not increase immediately following our expenditure of funds on a particular project. For example, if we build a new pipeline or expand an existing facility, the design, construction, development and installation may occur over an extended period of time and we may not receive any material increase in revenue or cash flow from that project until after it is placed in service and customers begin using the systems. If our revenues and cash flow do not increase at projected levels because of substantial unanticipated delays or other factors, we may not meet our obligations as they become due, and we may need to reduce or reprioritize our capital budget, sell non-strategic assets, access the capital markets or reassess our level of distributions to unitholders to meet our capital requirements.

Our growth strategies may be unsuccessful if we incorrectly predict operating results, or are unable to identify and complete future acquisitions or organic growth projects and integrate acquired or developed assets or businesses.

The acquisition and development of complementary midstream assets are components of our growth strategy. Acquisitions and organic growth projects present various risks and challenges, including:

In addition, we may be unable to identify acquisition targets and consummate acquisitions in the future. A portion of our strategy to grow our business and increase distributions to our unitholders is dependent on our ability to make acquisitions that result in an increase in distributable cash flow. The acquisition component of our growth strategy is based, in large part, on our expectation of ongoing divestitures by EEP of portions of its remaining ownership interest in Midcoast Operating to us over the next four to five years. We do not know when or if any such additional interests will be offered to us to purchase. The consummation and timing of any future acquisitions of these interests will depend upon, among other things, EEP’s willingness to offer these interests for sale to us, our ability to negotiate acceptable purchase agreements with respect to the interests and our ability to obtain financing on acceptable terms, and we can offer no assurance that we will be able to successfully consummate any future acquisition of additional interests in Midcoast Operating. Furthermore, if EEP reduces its ownership interest in us, it may be less willing to sell its remaining ownership interest in Midcoast Operating to us. In addition, there are no restrictions on EEP’s ability to transfer its ownership interest in Midcoast Operating to a third party.

Our gathering, processing and transportation contracts subject us to renewal risks.

We gather, purchase, process, treat, compress, transport and sell most of the natural gas and NGLs on our systems under contracts with terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal,

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gathering and processing customers with fixed-fee or fixed-spread contracts may desire to enter into gathering and transportation contracts under different fee arrangements, or a producer with whom we have a natural gas purchase contract may choose to enter into a transportation contract with us and retain title to its natural gas. In particular, a significant processing contract on our Anadarko system terminated in the third quarter of 2013. To the extent we are unable to renew or replace our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders could be materially and adversely affected.

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

Some of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets or reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could materially affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected. In addition, total insurance coverage for multiple insurable incidents exceeding coverage limits would be allocated by Enbridge on an equitable basis under an insurance allocation agreement.

Our operations are subject to all of the risks and hazards inherent in the gathering and transportation of natural gas and NGLs and the processing and treating of natural gas and fractionation of NGLs, including:

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. While we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

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

If third-party pipelines or other midstream facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our total segment margin and cash flow and our ability to make cash distributions to our unitholders could be adversely affected.

Our natural gas and NGL gathering and transportation pipelines and natural gas processing and treating facilities and NGL fractionation facilities connect to other pipelines or facilities owned and operated by unaffiliated third parties. The continuing operation of such third-party pipelines, processing plants, fractionation facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from hurricanes or other operational hazards. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurred, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our segment margin and ability to make cash distributions to our unitholders could be adversely affected. For example, following Hurricane Ike in 2008, the Mont Belvieu fractionation complex was shut down for a period of time due to loss of power. This shut down impacted our ability to process natural gas during the period at certain of our processing plants.

Our ability to access capital markets and credit on attractive terms to obtain funding for our capital projects and acquisitions may be limited.

Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Domestic and international economic conditions affect the functioning of capital markets and the availability of credit. Adverse economic conditions, such as those that became prevalent during the recessionary period of 2008 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 or ability to make distributions.

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

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Debt we or Midcoast Operating incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

In 2013, Midcoast Operating entered into a Financial Support agreement with EEP as the financial services provider, providing for guaranties of, and letters of credit obtained by, EEP on an aggregate amount not to exceed $700.0 million. We also issued $400.0 million of notes in a private placement offering on September 30, 2014. Our existing and future level of debt, as well as Midcoast Operating’s future level of debt, could have important consequences to us, including the following:

Our ability to service our debt and Midcoast Operating’s debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.

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

Our revolving credit facility limits our ability and Midcoast Operating’s ability to, among other things:

Our revolving credit facility contains covenants requiring us to maintain certain financial ratios. We are not permitted to allow our ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00. These covenants could limit our ability to undertake additional debt financing. Our ability to meet such financial ratios can be affected by events beyond our control, and we cannot assure that we will meet those ratios.

The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. Failure to comply with the provisions of our revolving credit facility could result in the occurrence of an event of default under the Credit Agreement, which would result in a cross-default under the note purchase agreement relating to the Notes. If an event of default were to occur, the lenders could, among other things, declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable.

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If the payment of our or Midcoast Operating’s debt is accelerated, our assets and Midcoast Operating’s assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

To the extent Midcoast Operating seeks a credit rating and receives less than an investment grade credit rating, or EEP terminates the Financial Support agreement with Midcoast Operating, Midcoast Operating could be required to provide collateral for Midcoast Operating’s hedging liabilities.

Currently, Midcoast Operating is party to certain International Swaps and Derivatives Association, Inc., or ISDA®, agreements associated with the derivative financial instruments we use to manage our exposure to fluctuations in commodity prices. These ISDA® agreements require Midcoast Operating to provide assurances of performance if counterparties’ exposure to Midcoast Operating exceeds certain levels or thresholds. EEP generally provides letters of credit on Midcoast Operating’s behalf to satisfy such requirements. At the close of the Offering, EEP entered into a Financial Support agreement with Midcoast Operating under which, during the term of the agreement, EEP will provide letters of credit and guarantees in support of Midcoast Operating’s financial obligations under derivative agreements and natural gas and NGL purchase agreements. Under the Financial Support agreement, EEP’s support of Midcoast Operating’s obligations will terminate on the earlier to occur of (1) the fourth anniversary of the closing of the Offering and (2) the date on which EEP owns, directly or indirectly (other than through its ownership interests in us), less than 20% of the total outstanding limited partner interest in Midcoast Operating.

Without an investment grade credit rating or financial support from EEP, we expect that Midcoast Operating will be required to provide letters of credit, cash collateral or other financial assurance with respect to new derivative agreements or purchase agreements that Midcoast Operating enters into. The amounts of any letters of credit Midcoast Operating provides under the terms of Midcoast Operating’s ISDA® agreements or other derivative financial instruments or agreements, or otherwise in support of our operations, would reduce the amount that we are able to borrow under our revolving credit facility. To the extent that EEP no longer provides this financial support or if we were otherwise required to guarantee the obligations currently guaranteed by EEP under the Financial Support agreement, the impact on our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders could be materially and adversely affected.

EEP’s credit ratings could adversely affect our ability to grow our business and our ability to obtain credit in the future.

EEP’s long-term credit ratings are currently investment grade. Although we do not have any indebtedness rated by any credit rating agency, we may have rated debt in the future. Credit rating agencies will likely consider EEP’s debt ratings when assigning ours because of EEP’s ownership interest in us and control of our operations. If one or more credit rating agencies were to downgrade the outstanding indebtedness of EEP or us, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our financial condition, results of operations and cash flows and our ability to grow our business and to make cash distributions to our unitholders.

Our logistics and marketing operations involve market and regulatory risks.

The primary role of our logistics and marketing business is to provide marketing services of natural gas, NGLs and condensate received from our gathering, processing and transportation businesses, thereby enhancing our competitive position. Our logistics and marketing business purchases natural gas, NGLs and condensate at prices determined by prevailing market conditions. Following our purchase of natural gas, NGLs and condensate, we generally resell the natural gas, NGLs, or condensate under sales contracts that are generally comparable in terms to our purchase contract, including any price escalation provisions. The profitability of our logistics and marketing operations may be affected by the following factors:

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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 material costs and liabilities.

Our pipeline, gathering, processing and trucking operations are subject to federal, state and local laws and regulations relating to environmental protection and operational and worker safety. Numerous governmental authorities have the power to enforce compliance with the laws and regulations they administer and permits they issue, often imposing complex requirements and necessitating capital expenditures or increased operating costs to achieve compliance, especially when activity is in the presence of sensitive elements like water crossings, wetlands and endangered species. Our failure to comply with these laws, regulations and operating permits can result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Our natural gas gathering, processing and transportation and NGL fractionation operations expose us to the risk of incurring significant environmental and safety-related costs and liabilities. Additionally, operational modifications, including pipeline restrictions, necessary to comply with regulatory requirements and resulting from our handling of natural gas and liquid hydrocarbons, historical environmental contamination, accidental releases or upsets, regulatory enforcement, litigation or safety and health incidents can also result in significant cost or limit revenues and volumes. In addition, environmental and operational safety laws and regulations, including but not limited to pipeline safety, wastewater discharge and air emission requirements, continue to become more stringent over time, particularly those related to the oil and gas industry. We may incur joint and several strict liability under these environmental laws and regulations in connection with discharges or releases of natural gas and liquid hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for gathering or processing activities for a number of years, often by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our natural gas and liquid hydrocarbons are handled or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage. We may also incur costs in the future due to changes in environmental and safety laws and regulations, or re-interpretations of enforcement policies or claims for personal, property or environmental damage. We may not be able to recover these costs from insurance or through higher rates.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

Because our operations, including our processing, treating and fractionation facilities and our compressor stations, are sources of greenhouse gases, legislation and regulations governing greenhouse gas emissions could increase our costs related to operating and maintaining our facilities, and could delay future permitting. At the federal level, the United States Congress has in the past and may in the future consider legislation to impose a tax

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on carbon or require a reduction of greenhouse gas emissions. On September 22, 2009, the EPA issued a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Subsequently, on November 30, 2010, the EPA issued a supplemental rulemaking that expanded the types of industrial sources that are subject to or potentially subject to the EPA’s mandatory greenhouse gas emissions reporting requirements to include petroleum and natural gas systems. These regulations were amended by the EPA in November 2014.

The EPA has concluded that the April 2010 issuance of regulations to control the greenhouse gas emissions from light duty motor vehicles (the “tailpipe rule”) automatically triggered provisions of the CAA that, in general, could potentially require stationary source facilities that emit more than 250 tons per year of carbon dioxide equivalent to obtain permits to demonstrate that best practices and technology are being used to minimize greenhouse gas emissions. On May 13, 2010, the EPA issued the “tailoring rule,” which served to establish the greenhouse gas emissions threshold for major new (and major modifications to existing) stationary sources. This rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit (Coalition for Responsible Regulation v. EPA), which dismissed the challenge on jurisdictional grounds. On appeal, the U.S. Supreme Court in 2013 (Utility Air Regulatory Group v. EPA) found the rule to be unlawful. Under the approach now being implemented by the EPA, for most purposes, new permitting provisions to control greenhouse gas emissions are required for new major source facilities that also emit 100,000 tons per year or more of carbon dioxide equivalent, of CO2e, and existing major source facilities making major modifications that also would increase greenhouse gas emissions by 75,000 CO2e. The EPA has indicated in rulemakings that it may further reduce the current regulatory thresholds for greenhouse gas emissions, making additional sources subject to permitting.

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.

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

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

Measurement adjustments on our pipeline system can materially affect our financial condition.

Natural gas and NGL measurement adjustments occur as part of the normal operating conditions associated with our pipelines. The quantification and resolution of measurement adjustments is complicated by several factors including: (1) the significant quantities (i.e., thousands) of measurement meters that we use throughout our systems, primarily around our gathering and processing assets; (2) varying qualities of natural gas and NGLs in the streams gathered and processed through our systems; and (3) variances in measurement that are inherent in metering technologies. Each of these factors may contribute to measurement adjustments that can occur on our systems and may materially affect our results of operations.

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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 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 processing plants, and 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. In August 2015, the EPA proposed regulations to reduce methane and volatile organic compound emissions from the oil and gas sector by 40 to 45 percent from 2012 levels by 2025. The proposed rule, which the EPA expects to finalize in 2016, would impose additional costs related to compliance with new emission limits as well as inspections and maintenance of several types of equipment used in our operations.

Future regulatory actions also have the potential to impact our operations. 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 emission 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 have been connected to hydraulic fracturing or to saltwater or drilling fluid disposal wells. In addition, at least one municipality in a state in which we operate, the City of Denton, Texas, 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 other legislation or regulation will be enacted and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs, and prohibitions for producers who drill near our pipelines. These factors could reduce the volumes of natural gas and NGLs available to move through our gathering and other

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systems, which could materially adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

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

The rates charged by several of our pipeline systems are regulated by the FERC or state regulatory agencies or both. These regulatory agencies also regulate other terms and conditions of the services these pipeline systems provide, including the types of services we may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose, the profitability of our pipeline businesses would suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which if delayed could further reduce our cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

The majority of our pipelines are not subject to regulation by the FERC; however, a change in the jurisdictional characterization of our assets, or a change in policy, could result in increased regulation of our assets which could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

The substantial majority of our pipeline assets are gas-gathering facilities or interests in gas-gathering facilities. Unlike interstate gas transportation facilities, natural gas gathering facilities are exempt from the jurisdiction of the FERC under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some cases non-discriminatory take requirements and complaint-based rate regulation. Although the FERC has not made a formal determination with respect to all of our facilities, we believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.

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

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

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Our gathering systems and intrastate pipelines are subject to state regulation that could materially and adversely affect our operations and cash flows.

State regulation of gathering facilities includes safety and environmental requirements. Several of our gathering systems are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to our rates and terms and conditions of service. State and local regulation may cause us to incur additional costs or limit our operations, may prevent us from choosing the customers to which we provide service, any or all of which could materially and adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

We do not own a majority of the land on which our pipelines are located, which could result in disruptions to our operations.

We do not own a majority of the land on which our pipelines are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations and our ability to make cash distributions to our unitholders.

Terrorist 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.

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

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

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

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

Our ability to operate our business effectively could be impaired if affiliates of our General Partner fail to attract and retain key management personnel.

We depend on the continuing efforts of the executive officers of our General Partner, all of whom are employees of affiliates of EEP’s general partner. Additionally, neither we nor our subsidiaries have employees. Our General Partner is responsible for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our General Partner, including our President and Principal Executive Officer. The loss of any member of our management or other key employees could have a material adverse effect on our business. Consequently, our ability to operate our business and implement our strategies will depend on the continued ability of affiliates of our General Partner to attract and retain highly skilled management personnel with midstream natural gas industry experience. Competition for these persons in the midstream natural gas industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

A shortage of skilled labor in the midstream natural gas industry could reduce labor productivity and increase costs, which could have a material adverse effect on our business and results of operations.

The gathering and transporting of natural gas and NGLs and the processing and treating of natural gas and fractionating of NGLs require skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially and adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our General Partner’s employees, our results of operations could be materially and adversely affected.

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Risks Inherent in an Investment in Us

EEP owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations and has limited duties to us and our unitholders. EEP, Enbridge and our General Partner have conflicts of interest with us and they may favor their own interests to the detriment of us and our other unitholders.

EEP, which is controlled by Enbridge Energy Management, L.L.C., or Enbridge Management, through a delegation of control agreement with EEP’s general partner, controls our General Partner, and appoints all of the officers and directors of our General Partner, some of whom are also officers or directors of EEP’s general partner, Enbridge Management or Enbridge. Although our General Partner has a duty to manage us in a manner that it believes is in the best interests of our partnership and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that they believe is in the best interests of EEP. Conflicts of interest may arise between EEP, Enbridge and their affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates, including EEP or Enbridge, over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner, including EEP and Enbridge, and result in less than favorable treatment of us and our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance growth externally; our cash distribution policy will significantly impair our ability to grow.

In addition, because we will distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our credit facility, on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our common and subordinated unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any additional units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce our distributable cash flow.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, after the subordination period has ended, our partnership agreement can be amended with the consent of our General Partner and the approval of a majority of the outstanding Class A common units and Class B common units (including Class A common units and Class B common units held by affiliates of our General Partner), voting together as a single class.

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Reimbursements due to our General Partner and its affiliates for services provided to us or on our behalf will reduce the amount of cash we have available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our General Partner.

Prior to making any distributions to our unitholders, we will reimburse our General Partner and its affiliates, including EEP, for expenses they incur and payments they make on our behalf. Our partnership agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The costs and expenses for which we are required to reimburse our General Partner and its affiliates are not subject to any caps or other limits. The reimbursement of expenses and payment of fees, if any, to our General Partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.

Because our common units will be yield-oriented securities, increases in interest rates could adversely impact our unit price and our ability to issue equity or incur debt for acquisitions or other purposes.

As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and the cost to us of any such issuance or incurrence. In addition, interest rates on our future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.

Our partnership agreement replaces our General Partner’s fiduciary duties to our limited partners with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary duties to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. In addition, our partnership agreement restricts the remedies available to our limited partners for actions that might constitute breaches of fiduciary duty under applicable state law. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. When acting in its individual capacity, our General Partner is entitled to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or any limited partner. By purchasing a common unit, a unitholder is deemed to have consented to the provisions in our partnership agreement, including the provisions discussed above.

Our partnership agreement limits our General Partner’s liabilities and the remedies available to our limited partners for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to our limited partners for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

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In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by the board of directors or the conflicts committee of the board of directors of our General Partner must be made in good faith and that our conflicts committee and the board of directors of our General Partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our General Partner may elect to cause us to issue Class B common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the conflicts committee of our General Partner’s board or our unitholders. This election may result in lower distributions to our unitholders in certain situations.

Our General Partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled for each of the prior four consecutive fiscal quarters (and the amount of each such distribution did not exceed adjusted operating surplus for each such quarter), to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Furthermore, our General Partner has the right to transfer all or any portion of the incentive distribution rights at any time, and such transferee shall have the same rights as the General Partner relative to resetting target distributions if our General Partner concurs that the tests for resetting target distributions have been fulfilled. Following a reset election by our General Partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

In the event of a reset of our minimum quarterly distribution and target distribution levels, our General Partner will be entitled to receive, in the aggregate, a number of Class B common units equal to that number of Class B common units that would have entitled the holder of such units to an aggregate quarterly cash distribution in the two-quarter period prior to the reset election equal to the distribution to our General Partner on the incentive distribution rights in the quarter prior to the reset election prior two quarters. Our General Partner will also be issued the number of General Partner units necessary to maintain its General Partner interest in us that existed immediately prior to the reset election (currently 2.0%). We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per Class A common unit without such conversion; however, it is possible that our General Partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our General Partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our General Partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued Class B common units, which, along with the Class A common units, are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the General Partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. As a result, a reset election may cause holders of our Class A common units and Class B common units to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued Class B common units to our General Partner in connection with resetting the target distribution levels related to our General Partner’s incentive distribution rights.

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

Unitholders have only limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our General Partner or the board of directors of our General Partners and will have no right to elect our General Partner or the board of directors or our General Partner on an

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annual or other continuing basis. The directors of our General Partner are chosen by EEP. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The unitholders will be unable initially to remove our General Partner without its consent because our General Partner and its affiliates will own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding Class A common units, Class B common units and subordinated units voting together as a single class is required to remove our General Partner. Our General Partner and its affiliates own approximately 51.9% of the total outstanding Class A common units, Class B common units and subordinated units on an aggregate basis, excluding common units purchased by directors and officers of our General Partner and Enbridge Management under our directed unit program. Also, if our General Partner is removed without cause as defined under our partnership agreement during the subordination period, and common units and subordinated units held by our General Partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into Class B common units and any existing arrearages on the Class A common units will be extinguished. A removal of our General Partner under these circumstances would adversely affect the Class A common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.

Our General Partner units or the control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its General Partner units to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of EEP to transfer its membership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the directors and officers of our General Partner with its own designees.

The incentive distribution rights of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our General Partner transfers its incentive distribution rights to a third party but retains its General Partner interest, our General Partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our General Partner could reduce the likelihood of EEP selling or contributing additional midstream assets to us, as EEP would have less of an economic incentive to grow our business, which in turn could impact our ability to grow our asset base.

We may issue additional partnership securities without unitholder approval, which would dilute unitholder interests.

At any time, we may issue an unlimited number of additional partnership securities without the approval of our unitholders and our existing unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, there are no limitations in our partnership

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agreement on our ability to issue partnership securities that rank equal or senior to our common units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional common units or other partnership securities of equal or senior rank will have the following effects:

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

As of December 31, 2015, EEP holds 1,335,056 Class A common units and 22,610,056 subordinated units. All of the subordinated units will convert into Class B common units on a one-for-one basis at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide EEP with certain registration rights under applicable securities laws.

Our General Partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our partnership agreement requires our General Partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits our General Partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to our unitholders.

Our General Partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 80% of our then-outstanding Class A common units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us to acquire all, but not less than all, of the Class A common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of our Class A common units over the 20 trading days preceding the date that is three business days before the General Partner exercises this right and (2) the highest per-unit price paid by our General Partner or any of its affiliates for Class A common units during the 90-day period preceding the date such notice is first mailed. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of this limited call right. There is no restriction in our partnership agreement that prevents our General Partner from issuing additional Class A common units and exercising its limited call right. If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The

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limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for any or all of our obligations as if you were a general partner if a court or government agency were to determine that:

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

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

Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers or other employees.

Our partnership agreement provides, that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any of our, or our General Partner’s, directors, officers, or other employees, or owed by our General Partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in our common units is deemed to have received notice of and consented to the foregoing provisions. Although we believe this choice of forum provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against us and our General Partner’s directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings and it is possible that in connection with any action a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action. If a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations and our ability to make cash distributions to our unitholders.

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

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

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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.

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 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 that results from that income.

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

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we have taken or may take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our positions and such positions may not ultimately be sustained. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our distributable cash flow.

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

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

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

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

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

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Item 2. Properties

The map below presents the location of our current natural gas systems assets, projects being constructed and joint ventures. This map also depicts some assets owned or under development by us to provide an understanding of how they relate to our business.

Descriptions of these properties of our 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 natural gas systems have natural gas compressor stations, processing plants and treating plants, the vast majority of which are located on land that is owned by us, with the remainder used by us under easements, leases or permits.

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

Substantially all of our pipelines are constructed on rights-of-way granted by the record owners of the property. In some instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, and state highways and, in some instances, these permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. Although such revocations are unlikely to be exercised, in nearly all instances continued payment of rentals and license fees, or relocations to accommodate a public authority or railroad ensures continued operation of the affected system. In some states and under some circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines.

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Under our omnibus agreement, EEP will indemnify us for any failure to have certain rights-of-way, leaseholds, consents, licenses and permits necessary to own and operate our assets in substantially the same manner that they were owned and operated prior to the Offering. EEP’s indemnification obligation is limited to losses for which we notify EEP prior to November 13, 2016 and is subject to a $500,000 aggregate deductible before we are entitled to indemnification and a $15.0 million aggregate cap.

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 15. Commitments and Contingencies, address the matters required by this item and are incorporated herein by reference. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 4. Mine Safety Disclosures

None.

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PART II

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

Our Class A common units are listed and traded on the NYSE, the principal market for the Class A common units, under the symbol “MEP.” The quarterly price ranges per Class A common unit and cash distributions paid per unit for 2015 and 2014 are summarized as follows:

		First				Second				Third				Fourth
2015 Quarters
High		$	16.00			$	15.17			$	13.36			$	13.58
Low		$	11.41			$	10.27			$	8.75			$	6.50
Cash distributions paid		$	0.3425			$	0.3475			$	0.3525			$	0.3575

		First				Second				Third				Fourth
2014 Quarters
High		$	22.29			$	22.93			$	25.13			$	23.09
Low		$	19.16			$	20.55			$	18.96			$	12.50
Cash distributions paid		$	0.1664			$	0.3125			$	0.3250			$	0.3375

On February 12, 2016, the last reported sales price of our Class A common units on the NYSE was $7.00. As of January 22, 2016, there were four 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 subordinated units, all of which are held by EEP.

Under our current cash distribution policy, we intend to make quarterly distributions to the holders of our Class A common units and subordinated units to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to our General Partner and its affiliates. Our current cash distribution policy is also subject to certain restrictions, as well as the considerable discretion of our General Partner in determining the amount of our available cash each quarter. These restrictions include restrictions under our Credit Agreement, general partner discretion to establish reserves and to take other actions provided by our partnership agreement, and the performance of our subsidiaries. For further information about distributions and about these and other limitations and risks related to distributions, please read Item 1A. Risk Factors and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Distributions.

On July 29, 2015, the partners of Midcoast Operating approved an amendment to Midcoast Operating’s limited partnership agreement that could enhance our distributable cash flow, demonstrating EEP’s further support of our ongoing cash distribution strategy and growth outlook. For further information about our funding arrangements with our General Partner, please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Funding Arrangements with EEP.

ISSUER PURCHASES OF EQUITY SECURITIES

The following table provides information as of December 31, 2013, with respect to Class A common units that we purchased from Enbridge Energy Partners. There were no units repurchased in 2015 or 2014:

Period		Total number of units purchased				Average price paid per unit				Total number of units purchased as part of publicly announced plans or programs				Maximum number (or approximate dollar value) of units that may yet be purchased under the plans or programs
October 1 – October 31			—			$	—				—				—
November 1 – November 30(1)			2,775,000			$	16.94				—				—
December 1 – December 31			—			$	—				—				—
Total			2,775,000			$	16.94				—				—

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Item 6. Selected Financial Data

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

		December 31,
		2015				2014				2013				2012(1)				2011(1)
		(in millions, except per unit amounts)
Income Statement Data:(2)
Operating revenues		$	2,842.7			$	5,894.3			$	5,593.6			$	5,357.9			$	7,828.2
Operating expenses			3,125.2				5,741.6				5,528.5				5,186.5				7,608.9
Operating income (loss)			(282.5	)			152.7				65.1				171.4				219.3
Interest expense, net			(29.5	)			(16.7	)			(1.7	)			—				—
Equity in earnings of joint ventures			29.2				13.2				—				—				—
Other income (expense)			(0.3	)			(0.3	)			(1.2	)			(0.1	)			2.8
Income tax expense			(1.4	)			(4.6	)			(8.3	)			(3.8	)			(2.9	)
Net income (loss)		$	(284.5	)		$	144.3			$	53.9			$	167.5			$	219.2
Predecessor income prior to initial public offering (from January 1, 2013 through November 12, 2013)										$	56.3
Net loss subsequent to initial public offering to Midcoast Energy Partners, L.P. (from November 13, 2013 through December 31, 2013)										$	(2.4	)
Net income (loss) attributable to noncontrolling interest		$	(120.6	)		$	80.2			$	(0.6	)
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.		$	(163.9	)		$	64.1			$	(1.8	)
Net income (loss) attributable to limited partner ownership interest(4)		$	(160.5	)		$	62.8			$	19.7			$	64.0			$	83.8
Net income (loss) per limited partner unit (basic and diluted)(4)		$	(3.55	)		$	1.39			$	0.68			$	2.40			$	3.14
Cash distributions paid per limited partner unit outstanding		$	1.40			$	1.14
Financial Position Data (at year end):(2)(3)
Property, plant and equipment, net		$	4,226.3			$	4,159.7			$	4,082.3			$	3,963.0			$	3,651.3
Total assets			5,273.9				5,754.1				6,036.4				5,667.4				5,134.6
Long-term debt, excluding current maturities			890.0				760.0				335.0				—				—
Partners’ capital:
Predecessor partner interest			—				—				—				4,707.1				4,277.8
Class A common units			522.2				634.2				495.3				—				—
Subordinated units			1,062.0				1,174.0				1,035.1				—				—
General Partner units			43.3				47.8				42.2				—				—
Accumulated other comprehensive income (loss)			(0.9	)			11.6				(3.1	)			7.1				(28.7	)
Noncontrolling interest			2,405.7				2,529.0				2,983.2				—				—
Partners’ capital		$	4,032.3			$	4,396.6			$	4,552.7			$	4,714.2			$	4,249.1
Cash Flow Data:(2)(3)
Cash flows provided by operating activities		$	207.0			$	159.1			$	420.9			$	352.7			$	415.6
Cash flows used in investing activities		$	197.4			$	231.3			$	522.3			$	614.5			$	480.1
Cash flows provided by financing activities		$	8.4			$	67.3			$	106.3			$	261.8			$	64.5
Additions to property, plant and equipment, acquisitions and investment in joint venture included in investing activities, net of cash acquired		$	239.1			$	274.6			$	462.9			$	621.1			$	484.0

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

Date of Unit Issuance		Class of Limited Partnership Interest				Number of Units Issued				Net Proceeds Including General Partner Contribution
										(in millions)
December 2013			Class A				2,775,000			$	47.0
November 2013			Class A				18,500,000			$	304.5

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.

Items Affecting the Comparability of Our Financial Results

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

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RESULTS OF OPERATIONS — OVERVIEW

We are a growth-oriented Delaware limited partnership formed by EEP to serve as EEP’s primary vehicle for owning and growing its natural gas and NGL midstream business in the United States. Midcoast Operating is a Texas limited partnership that owns a network of natural gas and NGL gathering and transportation systems, natural gas processing and treating facilities and a NGL fractionation facility primarily located in Texas and Oklahoma. Midcoast Operating also owns and operates NGL and condensate logistics and marketing assets that primarily support its gathering, processing and transportation business. Through our ownership of Midcoast Operating’s general partner, we control, manage and operate these systems.

We gather natural gas from the wellhead and central receipt points on our systems, deliver it to our facilities for processing and treating and redeliver the residue gas to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies. We deliver the NGLs produced at our processing plants to intrastate pipelines and interstate pipelines for transportation to the NGL market hubs in Mont Belvieu, Texas and Conway, Kansas. We also deliver a portion of NGLs produced at our fractionation facility at one of our processing plants to a wholesale customer. In addition, we also provide marketing services of natural gas and NGLs to wholesale customers.

On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Logistics and Marketing segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third-party buyer. Since that date, Midcoast Operating subsidiaries sell their natural gas products directly to third parties, instead of through the Logistics and Marketing segment.

Our financial condition and results of operations are subject to variability from multiple factors, including:

We conduct our business through two distinct reporting segments: Gathering, Processing and Transportation and Logistics and Marketing. We have established these reporting segments as strategic business units to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

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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)
Gathering, Processing and Transportation		$	(224.2	)		$	114.9			$	70.2
Logistics and Marketing			(53.6	)			43.5				(5.1	)
Corporate			(4.7	)			(5.7	)			—
Total operating income (loss)			(282.5	)			152.7				65.1
Interest expense			(29.5	)			(16.7	)			(1.7	)
Other income (loss)			28.9				12.9				(1.2	)
Income tax expense			(1.4	)			(4.6	)			(8.3	)
Net income (loss)		$	(284.5	)		$	144.3			$	53.9
Less: Predecessor income prior to initial public offering (from January 1, 2013 through November 12, 2013)											56.3
Net loss subsequent to initial public offering attributable to Midcoast Energy Partners, L.P. (from November 13, 2013 through December 31, 2013)											(2.4	)
Less: Net income (loss) attributable to noncontrolling interest			(120.6	)			80.2				(0.6	)
Net income (loss) attributable to general and limited partner ownership interest in Midcoast Energy Partners, L.P.		$	(163.9	)		$	64.1			$	(1.8	)

Derivative Transactions and Hedging Activities

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

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not receive hedge accounting in our consolidated statements of income as “Operating revenue” and “Cost of natural gas and natural gas liquids.”

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

		December 31,
		2015				2014				2013
		(in millions)
Gathering, Processing and Transportation segment:
Hedge ineffectiveness		$	(4.1	)		$	5.6			$	3.3
Non-qualified hedges			(31.2	)			123.6				3.3
Logistics and Marketing segment:
Non-qualified hedges			(23.0	)			29.2				(9.6	)
Derivative fair value net gains (losses)		$	(58.3	)		$	158.4			$	(3.0	)

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RESULTS OF OPERATIONS — BY SEGMENT

Gathering, Processing and Transportation

Our gathering, processing and transportation business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. Revenues for our gathering, processing and transportation business are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported and sold through our systems; the volumes of NGLs sold; and the level of natural gas, NGL and condensate prices. The segment gross margin of our gathering, processing and transportation business, which we define as revenue generated from gathering, processing and transportation operations less the cost of natural gas and natural gas liquids purchased, is derived from the compensation we receive from customers in the form of fees or commodities we receive for providing our services, in addition to the proceeds we receive for the sales of natural gas, NGLs and condensate to affiliates and third parties.

The following tables set forth the operating results of our Gathering, Processing and Transportation segment and the approximate average daily volumes of natural gas throughput and NGLs produced on our major systems for the years ended December 31, 2015, 2014, and 2013.

		December 31,
		2015				2014				2013
		(in millions)
Operating revenues		$	588.5			$	647.3			$	729.0
Cost of natural gas and natural gas liquids			173.8				27.1				157.6
Segment gross margin			414.7				620.2				571.4
Operating and maintenance			216.0				260.6				278.9
General and administrative			67.3				87.1				86.6
Goodwill impairment			206.1				—				—
Asset impairment			—				15.6				—
Depreciation and amortization			149.5				142.0				135.7
Operating expenses			638.9				505.3				501.2
Operating income (loss)			(224.2	)			114.9				70.2
Other income (expense)			29.3				12.9				(1.5	)
Net income (loss)		$	(194.9	)		$	127.8			$	68.7
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 Gathering, Processing and Transportation segment for the year ended December 31, 2015, decreased $339.1 million, as compared with the year ended December 31, 2014, primarily due to the $206.1 million goodwill impairment charge recorded during 2015. We performed a goodwill impairment analysis after we learned from customers, during the second quarter 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 $206.1 million in goodwill was impaired.

Segment gross margin decreased $205.5 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, in part due to a decrease of $164.5 million from non-cash, mark-to-market losses of $35.3 million and gains of $129.2 million for the years ended December 31, 2015 and 2014, respectively. These losses are primarily related to the reclassification of previously recognized unrealized mark-to-market gains as the underlying transactions were settled, coupled with decreased non-cash, mark-to-market net gains due to smaller decreases in average forward prices during 2015 than in 2014.

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

Segment gross margin decreased $28.7 million for the year ended December 31, 2015, compared to the year ended December 31, 2014, due to reduced natural gas production volumes. The average daily volumes of our major systems for the year ended December 31, 2015, decreased by approximately 148,000 million British Thermal units per day, or MMBtu/d, or 7% when compared to the year ended December 31, 2014. The average NGL production for the year ended December 31, 2015, decreased by 2,043 Bpd, or 2%, when compared to the year ended December 31, 2014. The decrease in natural gas and NGL volumes was primarily attributable to the 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.

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.

Operating and maintenance and general and administrative costs together decreased $64.4 million for the year ended December 31, 2015, when compared to the year ended December 31, 2014, primarily due to cost reduction efforts undertaken by management, including $9.7 million in workforce reductions, which resulted in a decrease in contract labor as well as other related cost benefits.

Depreciation and amortization expense for our Gathering, Processing and Transportation segment increased $7.5 million, for the year ended December 31, 2015, compared with the year ended December 31, 2014, due to additional assets that were placed into service.

Other income increased $16.4 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, primarily due to increases in equity earnings on our investment in the Texas Express NGL system. These increases were a result of higher volumes and increases in ship-or-pay commitments during 2015.

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

The operating income of our Gathering, Processing and Transportation segment for the year ended December 31, 2014, increased $44.7 million, as compared with the year ended December 31, 2013. The most significant area affected was segment gross margin, which increased $48.8 million for the year ended December 31, 2014, as compared with the year ended December 31, 2013.

Segment gross margin increased $122.6 million for the year ended December 31, 2014, when 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 and condensate 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.

Segment gross margin increased $5.8 million for the year ended December 31, 2014, as compared with the year ended December 31, 2013, due to increased margins from higher commodity prices, net of hedges, related to contracts where we paid in commodities for our services.

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, 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 reduced 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.

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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 of 2014, which significantly disrupted producer wellhead production levels and our pipeline operations compared to the year ended December 31, 2013.

Operating and maintenance costs decreased $18.3 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 2014, the company took actions to reduce its costs through a workforce reduction, which increased severance costs by $4.3 million for the year ended December 31, 2014, as compared with the year ended December 31, 2013.

Depreciation and amortization expense for our Gathering, Processing and Transportation segment increased $6.3 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 Gathering, Processing and Transportation

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 low 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 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 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.

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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 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 EEP based on our proportionate ownership percentages in Midcoast Operating, which currently are 51.6% and 48.4%, 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 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.

On February 27, 2015, we acquired from NGR its midstream operations in Leon, Madison and Grimes counties, Texas. The acquisition consisted of a natural gas gathering system currently in operation. For further details regarding the NGR acquisition, see Item 1. Financial Statements Note 4. Acquisitions and Dispositions.

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 EEP based on our proportionate ownership percentages in Midcoast Operating, subject to market conditions and our financing capacity.

Logistics and Marketing

The primary role of our logistics and marketing business is to provide marketing services of natural gas, NGLs and condensate received from our gathering, processing and transportation business. We purchase and receive natural gas, NGLs and other products from pipeline systems and processing plants and sell and deliver them to wholesale customers, distributors, refiners, fractionators, chemical facilities, various third parties and end users. Our Logistics and Marketing segment derives a majority of its operating income from selling natural gas, NGLs and condensate received from producers on our Gathering, Processing and Transportation segment pipeline assets. A majority of the natural gas and NGLs we purchase are produced in Texas markets where we have expanded third-party pipeline deliverability alternatives over the past several years. We use our connectivity to interstate pipelines to improve value for the producers by delivering natural gas into premium markets and NGLs to primary markets where we sell them to major customers. Additionally, our Logistics and Marketing segment derives operating income from providing logistics services for our customers from the wellhead to markets.

On September 1, 2015, two wholly-owned subsidiaries of Midcoast Operating in the Logistics and Marketing segment sold certain natural gas inventories and assigned certain storage agreements, transportation contracts and other arrangements to a third party. Since that date, Midcoast Operating subsidiaries sell their natural gas products directly to third parties, instead of through the Logistics and Marketing segment, which has seen reduced activity related to the sale of natural gas as a result of that transaction.

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The following table sets forth the historical operating revenues and cost of natural gas and natural gas liquids of these subsidiaries prior to the transaction:

		For the years ended December 31,
		2015				2014				2013
		(in millions)
Operating revenues		$	898.0			$	2,187.9			$	1,780.6
Cost of natural gas and natural gas liquids			886.6				2,173.1				1,777.4
Segment gross margin		$	11.4			$	14.8			$	3.2

The decrease in operating revenues and cost of natural gas and natural gas liquids is primarily due to decreases in commodity prices as well as decreases in volumes from lower drilling activities. Further, while we expect that operating revenues and cost of natural gas and natural gas liquids will be reduced in the Logistics and Marketing segment in future periods due to the transaction discussed above, we do not expect a significant impact on consolidated segment gross margin as a result. In addition, we believe that some of these revenues and costs of natural gas and natural gas liquids, and the related gross margin, will be recognized in the Gathering, Processing and Transportation segment in future periods as Midcoast Operating subsidiaries in that segment will sell their natural gas products directly to third parties.

The following table sets forth the operating results of our Logistics and Marketing segment for the years ended December 31, 2015, 2014, and 2013:

		December 31,
		2015				2014				2013
		(in millions)
Operating revenues		$	2,254.2			$	5,247.0			$	4,864.6
Cost of natural gas and natural gas liquids			2,199.1				5,118.8				4,779.5
Segment gross margin			55.1				128.2				85.1
Operating and maintenance			56.0				62.9				71.4
General and administrative			11.7				12.4				11.6
Goodwill impairment			20.4				—				—
Asset impairment			12.3				—				—
Depreciation and amortization			8.3				9.4				7.2
Operating expenses			108.7				84.7				90.2
Operating income (loss)		$	(53.6	)		$	43.5			$	(5.1	)

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

The operating income of our Logistics and Marketing segment for the year ended December 31, 2015, decreased $97.1 million, as compared with the year ended December 31, 2014. Decreases in “Operating revenues” and “Cost of natural gas and natural gas liquids” for the year ended December 31, 2015, as compared with the year ended December 31, 2014, are primarily due to decreases in commodity prices and the resulting decreased volumes from lower drilling activities.

The most significant area affected was segment gross margin, which decreased $73.1 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014. In addition, for the year ended December 31, 2015, the Logistics and Marketing segment recognized a $20.4 million goodwill impairment charge and a non-cash impairment charge of $12.3 million from an expected loss on disposal of our non-core, held-for-sale assets. The goodwill impairment resulted from the impacts on our marketing business from sustained reductions in drilling activities in the areas in which our Gathering, Processing and Transportation segment operates.

Segment gross margin experienced a net decrease of $52.2 million including $1.6 million of gains associated with the assignments of certain natural gas contracts, due to non-cash, mark-to-market losses for the year ended December 31, 2015, as compared with the year ended December 31, 2014. These losses are primarily related to the reclassification of previously recognized unrealized mark-to-market gains as the underlying transactions were settled, coupled with decreased non-cash, mark-to-market net gains due to smaller decreases in average forward prices during 2015 than in 2014.

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Our segment gross margin also decreased $9.3 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, due to costs associated with the sale of certain natural gas inventories, and assignment of certain storage agreements, transportation contracts and other arrangements to a third party.

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

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

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

Operating and maintenance and general and administrative costs together decreased $7.6 million for the year ended December 31, 2015, as compared with the year ended December 31, 2014, primarily due to a decrease in outside contract labor as well as other related benefit costs due to workforce reductions in December 2014. In addition, other cost reduction efforts have resulted in reduced repairs and maintenance costs.

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

The operating income of our Logistics and Marketing segment for the year ended December 31, 2014, increased $48.6 million, as compared with the year ended December 31, 2013. The most significant area affected was segment gross margin, which increased $43.1 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 $38.8 million for the year ended December 31, 2014, compared to the year ended December 31, 2013 primarily from gains due to the NGL forward contracts and the non-qualifying commodity derivatives we use to economically hedge a portion of the NGLs resulting from the operating activities of our Logistics and Marketing segment, compared to losses in the year ended December 31, 2013.

Segment gross margin increased $9.8 million for the year ended December 31, 2014, as compared with 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.

Operating and administrative costs decreased $7.7 million for the year ended December 31, 2014, as compared with the year ended December 31, 2013, due partly to lower volumes received from our Gathering, Processing and Transportation segment and partly due to a strategic reduction of long hauls due to closer delivery points. Included in these amounts was $0.5 million in separation costs associated with workforce reductions.

Depreciation and amortization expense for the year ended December 31, 2014, increased $2.2 million for year ended December 31, 2014, as compared with the year ended December 31, 2013, due to additional assets that were placed into service.

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Corporate

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

		December 31,
		2015				2014				2013
		(in millions)
Operating and maintenance		$	1.1			$	0.4			$	—
General and administrative			3.6				5.3				—
Operating expenses			4.7				5.7				—
Operating loss			(4.7	)			(5.7	)			—
Interest expense, net			(29.5	)			(16.7	)			(1.7	)
Other income (loss)			(0.4	)			—				0.3
Income (loss) before income tax expense			(34.6	)			(22.4	)			(1.4	)
Income tax expense			(1.4	)			(4.6	)			(8.3	)
Net loss		$	(36.0	)		$	(27.0	)		$	(9.7	)

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

Interest expense increased $12.8 million for the year ended December 31, 2015, as compared to the same period in 2014, primarily due to a full year of interest expense incurred on our senior notes, which were issued in a private placement offering in September 2014.

Our income tax expense decreased $3.2 million for the year ended December 31, 2015, as compared to the same period in 2014, primarily due to a $3.5 million tax benefit from a reduction in deferred income tax payable and from an overall lower franchise tax rate in 2015. This reduction is the result of a reduction in the Texas franchise tax rate from the recently-enacted Texas Franchise Tax Reduction Act of 2015. Offsetting the reduction in the Texas franchise tax for the year ended December 31, 2015 was an increase in deferred income tax expense of approximately $2.4 million incurred due to a higher Texas franchise tax apportionment factor. See Note 17. Income Taxes for more information about this transaction.

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

General and administrative expenses increased $5.3 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013 due to increased professional fees and costs incurred since the Offering. Additionally, there was a full year of administrative expenses in 2014 when compared to costs in 2013 that were incurred only after our initial public offering on November 13, 2013.

Interest expense increased $15.0 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013, due to a full year of interest expense incurred on borrowings from our Credit Agreement in 2014. Additionally, we incurred three months of interest expense on our senior notes, which were issued in September 2014.

The state tax structure that exists in Texas imposes taxes that are based upon many, but not all, items included in net income. Income tax expense decreased $3.7 million primarily due to a tax law that was passed in June 2013 in the State of Texas, referred to as the 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 cost of goods sold, its depreciation, operations and maintenance costs related to the services provided. Under this law, we are allowed additional deductions against its income for Texas margin tax purposes. As a result, a one-time increase to deferred income tax expense of $6.0 million was recorded in 2013, and we incurred lower income tax expense in 2014.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary cash requirements relate to funding capital expenditures, meeting operational needs and paying distributions to our unitholders. We expect our ongoing sources of liquidity to include cash generated from operations of Midcoast Operating, borrowings under our senior revolving credit facility, which we refer to as the Credit Agreement, and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements, debt servicing requirements, and payment of quarterly cash distributions to our unitholders.

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We intend to pursue acquisitions of additional interests in our natural gas assets held through Midcoast Operating from EEP. EEP has indicated that it intends to offer us the opportunity to purchase additional interests in Midcoast Operating from time to time, although EEP is not legally obligated to do so. We do not know when, or if, EEP will offer to us any additional interest for purchase.

Available Liquidity

Our primary source of liquidity is provided by the Credit Agreement, the sources and uses of which at December 31, 2015, are set forth in the following table.

		(in millions)
Cash and cash equivalents		$	18.0
Total credit available under Credit Agreement		$	810.0
Amounts outstanding under Credit Agreement		$	(490.0	)
Total		$	338.0

The amounts we may borrow under the terms of our Credit Agreement are reduced by the face amount of our letters of credit outstanding.

Equity and Debt Financing Activities

Credit Agreement

We, Midcoast Operating, and our material domestic subsidiaries are parties to the Credit Agreement. The Credit Agreement is a committed syndicated senior revolving credit facility with related letter of credit and swing line facilities. On September 3, 2015, we amended our 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.

Our Credit Agreement also requires compliance with two financial covenants. We are not permitted to allow our ratio of consolidated funded debt to pro forma EBITDA (the total leverage ratio), as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. We must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00. These covenants could limit our ability to undertake additional debt financing.

At December, 31, 2015, we were 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 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 our 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 we 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 relating to 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 us 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, we had $490.0 million in outstanding borrowings under the Credit Agreement at a weighted average interest rate of 3.71%. Under the Credit Agreement, we 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. For further details regarding the Credit Agreement and the amendments thereto, refer to Item 8. Financial Statements and Supplementary Data, under Note 12. Debt.

Senior Notes

From time to time we issue long-term debt securities to finance our operations and meet outstanding debt obligations. In 2014, we completed a private offering of $400.0 million of notes consisting of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior

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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, and commenced on March 31, 2015.

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

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

At December 31, 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 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 12. Debt.

Financial Support Agreement

Midcoast Operating is party to a Financial Support Agreement with EEP, pursuant to which EEP provides letters of credit and guarantees, not to exceed $700.0 million in the aggregate at any time outstanding, in support of Midcoast Operating’s and its wholly owned subsidiaries’ financial obligations under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. At December 31, 2015, EEP provided $7.5 million of letters of credit outstanding and $21.7 million in guarantees. Midcoast Operating incurs a 2.5% annual fee based on the cumulative average amount of letter of credit and guarantees outstanding under this agreement. Midcoast Operating incurred $0.6 million of these costs at December 31, 2015. For further details regarding the Financial Support Agreement, refer to Item 8. Financial Statements and Supplementary Data, under Note 12. Debt.

Shelf-Registration Statement

Effective February 2, 2016, we terminated our shelf registration statement on Form S-3 filed with the Securities and Exchange Commission with a proposed aggregate offering price for all securities registered of $1.5 billion. No issuances had been made under this registration statement.

Funding Arrangements with EEP

One of our key strengths is our sponsorship from EEP. On July 29, 2015, the partners of Midcoast Operating approved an amendment to Midcoast Operating’s limited partnership agreement that could enhance our distributable cash flow, demonstrating EEP’s further support of our ongoing cash distribution strategy and growth outlook. The amendment provides a mechanism for us to receive increased quarterly distributions from Midcoast Operating and for EEP to receive reduced quarterly distributions if our declared distribution exceeds our distributable cash, as that term is defined in Midcoast Operating’s limited partnership agreement. Midcoast Operating’s adjustment of EEP’s distribution is limited by EEP’s pro rata share of the Midcoast Operating quarterly cash distribution and a maximum of $0.005 per unit quarterly distribution increase by us. There is no requirement for us to compensate EEP for these adjusted distributions, except for settling our capital accounts with Midcoast Operating in a liquidation scenario. The amendment to the limited partnership agreement and the support it provides to our cash distribution was effective with the quarter ended June 30, 2015, and continues through and including the distribution made for the quarter

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ending December 31, 2017. In 2015, we did not receive an increased allocation of cash distributions from the Midcoast Operating as distributable cash flow generated during each quarter exceeded the cash distribution amount we declared for payout.

Capital projects at Midcoast Operating are currently funded by us and by EEP based on our proportionate ownership percentages in Midcoast Operating, which are 51.6% and 48.4%, respectively. Under Midcoast Operating’s partnership agreement, we and EEP each have the option to contribute our proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund expansion capital expenditures or other growth projects. To the extent that we or EEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions to Midcoast Operating to the extent necessary to fully fund such expenditures in exchange for additional ownership interests in Midcoast Operating. In 2015, EEP provided approximately $38.9 million to fund its share of enhancement projects.

Under the Intercorporate Services Agreement, we reimburse EEP and its affiliates for the costs and expenses incurred in providing us with such services. EEP has agreed to reduce the amounts payable for general and administrative expenses that otherwise would have been allocable to Midcoast Operating by $25.0 million annually.

Sale of Accounts Receivable

We and certain of our subsidiaries are parties to a receivables purchase arrangement, which we refer to as the Receivables Agreement, with an indirect wholly owned subsidiary of Enbridge. 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 participating sellers, consisting of certain of our subsidiaries and certain EEP subsidiaries up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected.

At December 31, 2015, we sold and derecognized $2,157.6 million of receivables to an indirect wholly-owned subsidiary of Enbridge, and we received cash proceeds of $2,157.0 million. As of December 31, 2015, $147.1 million of the receivables were outstanding and had not been collected on behalf of the Enbridge subsidiary.

For further details regarding the Receivables Agreement, refer to Item 8. Financial Statements and Supplementary Data, under Note 14. Related Party Transactions.

Cash Requirements

Capital Spending

We categorize our capital expenditures as either maintenance or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which are worn, obsolete or completing its useful life. Examples of maintenance capital expenditures include expenditures to replace pipelines or processing facilities, to maintain equipment reliability, integrity and safety or to comply with existing governmental regulations and industry standards. We also include in maintenance capital expenditures a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital expenditures will increase due to the growth of our pipeline systems. We expect to fund our proportionate share of maintenance capital expenditures through operating cash flows.

Expansion capital expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards. Examples of expansion capital expenditures include the acquisition of additional assets or businesses, as well as capital projects that improve the service, integrity and safety capability of our existing assets, increase operating capacities or revenues, reduce operating costs from existing levels, or enable us to comply with new governmental regulations or industry standards. We anticipate funding our proportionate share of expansion capital expenditures temporarily through borrowings under our revolving credit facility, with long-term debt and equity funding being obtained when needed and as market conditions allow.

If EEP elects not to fund any capital expenditures at Midcoast Operating, we will have the option to fund all or a portion of EEP’s proportionate share of such capital expenditures in exchange for additional interests in Midcoast Operating. As a result, if our interests in Midcoast Operating increase, our proportionate share of the capital

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expenditures incurred by Midcoast Operating will also increase proportionate to our interest in Midcoast Operating. To the extent that EEP elects not to fund all or a portion of its proportionate share of Midcoast Operating’s capital expenditures, and we elect not to fund any capital expenditures not funded by EEP, we expect that Midcoast Operating will not pursue the applicable capital projects associated with such unfunded capital expenditures.

We incurred capital expenditures of $267.9 million for the year ended December 31, 2015, including $85.0 million for our NGR acquisition, $41.7 million of maintenance capital activities and $4.2 million of contributions to fund our joint ventures. At December 31, 2015, we had approximately $8.3 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment in the future.

Acquisitions

We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing them. We expect to obtain the funds needed to make acquisitions through a combination of cash flows from operating activities, borrowings under the Credit Agreement 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.

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 consisted of a natural gas gathering system currently in operation. This acquisition strengthened our position in the Eaglebine play, and will continue to allow us to offer gathering and processing services while leveraging assets on our existing footprint.

On July 1, 2014, we acquired an additional 12.6% limited partner interest in Midcoast Operating from EEP for $350.0 million, which brought our total ownership interest in Midcoast Operating to 51.6%. In addition, EEP has indicated that it intends to offer us the opportunity to purchase additional interests in Midcoast Operating from time to time. These acquisitions sometimes referred to as “drop-down” transactions, will provide an alternative source of funding for EEP while at the same time providing an opportunity for meaningful growth in our cash flows. However, EEP is under no obligation to offer to sell us additional interests in Midcoast Operating, and we are under no obligation to buy any such additional interests.

Forecasted Expenditures

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. The following table sets forth Midcoast Operating’s estimated maintenance and expansion capital expenditures of $45.0 million for the year ending December 31, 2016. Although we anticipate making these expenditures in 2016, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets.

		Total Forecasted Expenditures
		(in millions)
Capital Projects
Compression Capital		$	10
Well-connect Expansion Capital			20
Expansion Capital			20
Maintenance Capital Expenditures			40
			90
Less: Joint Funding from:
EEP(1)			45
		$	45

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Distributions

Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. For the year ended December 31, 2015, our annual cash distribution rate was $1.43 per unit. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our General Partner has considerable discretion to determine the amount of our available cash each quarter. In addition, our General Partner may change our cash distribution policy at any time, subject to the requirement in our partnership agreement to distribute all of our available cash quarterly. Generally, our available cash is our (1) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (2) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

Our partnership agreement provides that, during the subordination period, the Class A common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3125 per Class A common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the Class A common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the Class A common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution on the Class A common units from prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the Class A common units.

The subordination period began upon the closing of the Offering and will continue until the first business day following the distribution of available cash in respect of any quarter beginning after December 31, 2016, where each of the following conditions are met:

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ended December 31, 2014, where each of the following conditions are met:

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When the subordination period ends, the outstanding subordinated units will convert into Class B common units, and all Class A common units will no longer be entitled to arrearages. The Class B common units will be convertible at the option of the holder into Class A common units at any time that our General Partner determines, based on the advice of counsel, that the Class B common units to be converted have intrinsic, economic and federal income tax characteristics similar to the Class A common units.

At December 31, 2015, we have not met the test to end the subordination period.

Derivative Activities

We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at December 31, 2015 for each of the indicated calendar years:

		Notional(1)				2016				2017				2018				2019				2020 & Thereafter				Total(2)(3)
		(in millions)
Swaps:
Natural gas			13,266,817			$	—			$	0.3			$	—			$	—			$	—			$	0.3
NGL			4,611,100				9.9				(1.3	)			—				—				—				8.6
Crude Oil			2,008,900				0.7				—				—				—				—				0.7
Options:
Natural gas – puts purchased			1,647,000				2.1				—				—				—				—				2.1
Natural gas – puts written			1,647,000				(2.1	)			—				—				—				—				(2.1	)
Natural gas – calls written			1,647,000				—				—				—				—				—				—
Natural gas – calls purchased			1,647,000				—				—				—				—				—				—
NGL – puts purchased			4,242,100				54.4				5.8				—				—				—				60.2
NGL – puts written			91,500				(1.5	)			—				—				—				—				(1.5	)
NGL – calls written			4,242,100				(0.3	)			(0.8	)			—				—				—				(1.1	)
NGL – calls purchased			91,500				—				—				—				—				—				—
Crude Oil – puts purchased			1,352,700				27.7				10.0				—				—				—				37.7
Crude Oil – calls written			1,352,700				—				(0.6	)			—				—				—				(0.6	)
Forward contracts:
Natural gas			172,133,704				(2.8	)			0.1				0.1				0.1				—				(2.5	)
NGL			11,656,204				3.1				—				—				—				—				3.1
Crude Oil			588,287				—				—				—				—				—				—
Totals						$	91.2			$	13.5			$	0.1			$	0.1			$	—			$	104.9

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Summary of Obligations and Commitments

The following table summarizes the principal amount of our obligations and commitments at December 31, 2015:

		2016				2017				2018				2019				2020				Thereafter				Total
		(in millions)
Purchase commitments(1)		$	8.3			$	—			$	—			$	—			$	—			$	—			$	8.3
Operating leases			16.7				15.0				13.9				13.6				13.5				58.2				130.9
Right-of-way			0.5				0.2				0.2				0.2				0.1				0.8				2.0
Product purchase obligations(2)			44.2				15.4				24.8				25.5				26.5				85.9				222.3
Transportation/Service contract obligations(3)			56.1				112.9				125.2				129.2				125.5				338.7				887.6
Fractionation agreement obligations(4)			75.1				74.8				74.8				74.8				75.1				156.1				530.7
Total		$	200.9			$	218.3			$	238.9			$	243.3			$	240.7			$	639.7			$	1,781.8

The payments made under our obligations and commitments for the years ended December 31, 2015, 2014 and 2013 were $156.3 million, $1.7 billion and $334.4 million, respectively.

Cash Flow Analysis

The following table summarizes the changes in cash flows by operating, investing and financing for each of the years indicated:

		For the year ended December 31,
		2015				2014				2013
		(in millions)
Total cash provided by (used in):
Operating activities		$	207.0			$	159.1			$	420.9
Investing activities			(197.4	)			(231.3	)			(522.3	)
Financing activities			8.4				67.3				106.3
Net increase (decrease) in cash and cash equivalents			18.0				(4.9	)			4.9
Cash and cash equivalents at beginning of year			—				4.9				—
Cash and cash equivalents at end of period		$	18.0			$	—			$	4.9

Changes in our working capital accounts are shown in the following table and discussed below:

		For the year ended December 31,
		2015				2014				2013
		(in millions)
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other		$	2.9			$	33.2			$	7.9
Due from General Partner and affiliates			12.1				608.6				(633.9	)
Accrued receivables			173.5				(47.4	)			295.6
Inventory			43.8				(4.9	)			(12.2	)
Current and long-term other assets			10.1				(23.9	)			(14.3	)
Due to General Partner and affiliates			29.6				(468.2	)			522.8
Accounts payable and other			(11.7	)			(21.2	)			34.6
Accrued purchases			(231.4	)			(90.5	)			4.9
Interest payable			0.2				4.7				0.3
Property and other taxes payable			(2.5	)			1.1				3.4
Net change in working capital accounts		$	26.6			$	(8.5	)		$	209.1

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

Operating Activities

Net cash provided by our operating activities increased $47.9 million for the year ended December 31, 2015 compared with the year ended December 31, 2014, primarily due to increased cash from net income after non-cash adjustments of $12.8 million and increased cash from net changes in operating assets and liabilities of $35.1 million. The increase from net changes in operating assets and liabilities is primarily the result of general timing differences for cash receipts and payments and includes:

Investing Activities

Net cash used in our investing activities during the year ended December 31, 2015, decreased by $33.9 million, compared with the year ended December 31, 2014, primarily due to:

Financing Activities

Net cash provided by our financing activities decreased $58.9 million for the year ended December 31, 2015, compared with the year ended December 31, 2014, primarily due to:

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

Operating Activities

Net cash provided by our operating activities decreased $261.8 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to (1) a $146.8 million decrease in non-cash adjustments, and (2) a $217.6 million decrease in the change to our working capital accounts offset by increased distributions of $12.2 million from our joint ventures and a $90.4 million increase in net income.

The changes in our operating assets and liabilities, net of acquisitions as presented in our consolidated statements of cash flow for the year ended December 31, 2014, compared with the year ended December 31, 2013,

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is primarily the result of general timing differences for cash receipts and payments associated with our current and related party accounts. Other items affecting our cash flows from operating assets and liabilities include the following:

The decrease in non-cash items primarily consisted of increased derivative net gains of $161.4 million, primarily as a result of fluctuations in commodity prices, partially offset by an asset impairment charge of $15.6 million on our propylene line.

Investing Activities

Net cash used in our investing activities during the year ended December 31, 2014, decreased by $291.0 million, compared to the year ended December 31, 2013, primarily due to:

Financing Activities

Net cash provided by our financing activities decreased $39.0 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:

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OFF-BALANCE SHEET ARRANGEMENTS

We have no significant off-balance sheet arrangements.

SUBSEQUENT EVENTS

Distribution to Partners

On January 28, 2016, the board of directors of Midcoast Holdings, acting in its capacity as the General Partner of MEP, declared a cash distribution payable to our unitholders on February 12, 2016. The distribution was paid to unitholders of record as of February 5, 2016, of our available cash of $16.5 million at December 31, 2015, or $0.3575 per limited partner unit. We paid $7.6 million to our public Class A common unitholders, while $8.9 million in the aggregate was paid to EEP with respect to its Class A common units and subordinated units and Midcoast Holdings, with respect to its general partner interest.

Midcoast Operating Distribution

On January 28, 2016, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable on February 12, 2016 to its partners of record as of February 5, 2016. Midcoast Operating paid $27.6 million to us and $25.9 million to EEP.

RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Revenues from Contracts with Customers

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. In July 2015, the FASB delayed the effective date of the new revenue standard by one year. This accounting update is effective for annual and interim periods beginning on or after December 15, 2017, and may be applied on either a full or modified retrospective basis. We are currently evaluating which transition approach we will apply and the impact that this pronouncement will have on our consolidated financial statements.

Consolidation

In February 2015, the FASB issued Accounting Standards Update No. 2015-02, which addresses concerns about the current accounting for consolidation of certain legal entities. It makes targeted amendments to the current consolidation guidance and ends the deferral granted to certain entities from applying the variable interest entity, or VIE guidance. Among other things, the amended standard revised the consolidation model and certain guidance for limited partnerships, which included elimination of the presumption that a general partner should consolidate a limited partnership and the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships. This accounting update is effective for annual periods, and for interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted, and the new standard may be adopted either retrospectively or using a modified retrospective approach. We do not anticipate that our ultimate consolidation conclusions for non-wholly-owned subsidiaries will change upon adoption of the revised guidance. However, we believe that additional VIE disclosures will be required.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

For a summary of our significant accounting policies, refer to Item 8. Financial Statements and Supplementary Data, Note 2. Summary of Significant Accounting Policies. We believe our critical accounting policies discussed in the following paragraphs address the more significant judgments and estimates we use in the preparation of our consolidated financial statements. Each of these areas involves complex situations and a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that affect our consolidated financial statements. Our management has discussed the development and selection of the critical accounting policies and estimates related to the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent liabilities with the Audit, Finance & Risk Committee of Midcoast Holding’s board of directors.

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

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

Useful Lives of Property, Plant and Equipment

We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. Uncertainties that impact these assumptions include changes in laws and regulations that limit the estimated economic life of an asset, economic conditions and supply and demand in basins we serve. Based on the results of these assessments we may make modifications to the assumptions we use to determine our depreciation rates.

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Assessment of Recoverability of Property, Plant and Equipment and Intangible Assets

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. Our intangible assets primarily consist of customer contracts for the purchase and sale of natural gas, natural gas supply opportunities and contributions we have made in aid of construction activities that will benefit our operations, as well as workforce contracts and customer relationships. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. If the total of the undiscounted future cash flows is less than the carrying amount of the property, plant and equipment or intangible assets, we write the assets down to fair value. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of the recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

We believe the assumptions used in evaluating recoverability of our assets are appropriate and result in reasonable estimates of the fair values of our assets. However, the assumptions used are subject to uncertainty, and declines in the future performance or cash flows of our assets, changes in business conditions, such as commodity prices and drilling, or increases to our weighted average cost of capital assumptions due to changes in credit or equity markets may result in the recognition of impairment charges, which could be significant.

Derivative Financial Instruments

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding cost of natural gas we purchase for processing. Our exposure to commodity price risk exists within both of our segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices, as well as to reduce the volatility in our cash flows as they relate to inventories, firm commitments and certain anticipated transactions.

We record all derivative financial instruments at fair market value in our consolidated statements of financial position, which we adjust on a recurring basis each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the market approach, to value substantially all of our derivative instruments.

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

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

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Commitments and Contingencies

We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred. We believe these estimates are reasonable, however actual results could differ and it could result in material adjustments in results of operations between periods.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

COMMODITY PRICE RISK

Our net income and cash flows are subject to volatility stemming from fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL sales and the corresponding commodity costs of natural gas and natural gas liquids we purchase for processing. Our exposure to commodity price risk exists within our Gathering, Processing and Transportation and Logistics and Marketing segments. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices as well as to reduce volatility to our cash flows. Actively traded external market quotes, data from pricing services and published indices are used to value our derivative instruments. Our portfolio of derivative financial instruments is largely comprised of natural gas, NGL and crude oil sales and purchase contracts. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at December 31, 2015 and 2014.

		At December 31, 2015																								At December 31, 2014
										Wtd. Average Price(2)								Fair Value(3)								Fair Value(3)
		Commodity				Notional(1)				Receive				Pay				Asset				Liability				Asset				Liability
																		(in millions)
Portion of contracts maturing in 2016
Swaps
Receive variable/pay fixed			Natural Gas				16,287			$	2.52			$	3.48			$	—			$	—			$	—			$	(0.1	)
			NGL				1,482,500			$	20.77			$	26.39			$	0.2			$	(8.4	)		$	—			$	—
			Crude Oil				475,950			$	40.58			$	77.56			$	—			$	(17.5	)		$	—			$	(8.1	)
Receive fixed/pay variable			NGL				1,958,600			$	31.91			$	22.62			$	18.3			$	(0.2	)		$	9.3			$	—
			Crude Oil				437,950			$	82.70			$	40.89			$	18.2			$	—			$	9.1			$	—
Receive variable/pay variable			Natural Gas				5,124,000			$	2.50			$	2.49			$	0.1			$	(0.1	)		$	0.5			$	(0.3	)
Physical Contracts
Receive variable/pay fixed			NGL				180,000			$	31.22			$	32.31			$	—			$	(0.2	)		$	—			$	—
			Crude Oil				55,166			$	37.69			$	40.61			$	—			$	(0.2	)		$	—			$	—
Receive fixed/pay variable			NGL				838,119			$	28.52			$	26.54			$	1.9			$	(0.2	)		$	—			$	—
			Crude Oil				13,316			$	36.40			$	37.46			$	—			$	—			$	—			$	—
Receive variable/pay variable			Natural Gas				165,210,634			$	2.30			$	2.31			$	—			$	(2.8	)		$	0.7			$	(0.4	)
			NGL				10,638,085			$	16.53			$	16.37			$	4.0			$	(2.4	)		$	—			$	—
			Crude Oil				519,805			$	37.16			$	36.79			$	0.7			$	(0.5	)		$	—			$	—
Portion of contracts maturing in 2017
Swaps
Receive variable/pay fixed			Natural Gas				76,530			$	2.48			$	2.97			$	—			$	—			$	—			$	—
			NGL				547,500			$	17.38			$	25.86			$	—			$	(4.5	)		$	—			$	—
			Crude Oil				547,500			$	46.47			$	66.72			$	—			$	(10.9	)		$	—			$	—
Receive fixed/pay variable			NGL				622,500			$	21.61			$	16.28			$	3.3			$	(0.1	)		$	0.7			$	—
			Crude Oil				547,500			$	66.78			$	46.47			$	10.9			$	—			$	0.8			$	—
Receive variable/pay variable			Natural Gas				8,050,000			$	2.64			$	2.60			$	0.5			$	(0.2	)		$	—			$	—
Physical Contracts
Receive variable/pay variable			Natural Gas				2,187,810			$	2.81			$	2.79			$	0.1			$	—			$	0.2			$	(0.1	)
Portion of contracts maturing in 2018
Physical Contracts
Receive variable/pay variable			Natural Gas				2,187,810			$	2.98			$	2.95			$	0.1			$	—			$	—			$	—
Portion of contracts maturing in 2019
Physical Contracts
Receive variable/pay variable			Natural Gas				2,187,810			$	3.14			$	3.11			$	0.1			$	—			$	—			$	—
Portion of contracts maturing in 2020
Physical Contracts
Receive variable/pay variable			Natural Gas				359,640			$	3.45			$	3.42			$	—			$	—			$	—			$	—