10-K 1 d871102d10k.htm 10-K 10-K
Table of Contents

 

 

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, 2014

or

 

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

For the transition period from                    to                    

Commission file number 1-10934

 

ENBRIDGE ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware   39-1715850

(State or Other Jurisdiction of

Incorporation or Organization)

  (I.R.S. Employer Identification No.)

1100 Louisiana Street, Suite 3300,

Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code

(713) 821-2000

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

 

Title of each class

 

Name of each exchange on which registered

Class A common units   New York Stock Exchange

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

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  ¨    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  ¨

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  ¨

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.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ¨    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, 2014, was $7,667,339,293.

As of February 13, 2015 the registrant has 254,208,428 Class A common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 


Table of Contents

TABLE OF CONTENTS

 

     Page  
  PART I   

Item 1.

  Business      1   

Item 1A.

  Risk Factors      35   

Item 2.

  Properties      56   

Item 3.

  Legal Proceedings      57   

Item 4.

  Mine Safety Disclosures      57   
  PART II   

Item 5.

  Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities      58   

Item 6.

  Selected Financial Data      59   

Item 7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      62   

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk      116   

Item 8.

  Financial Statements and Supplementary Data      126   

Item 9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      207   

Item 9A.

  Controls and Procedures      207   

Item 9B.

  Other Information      208   
  PART III   

Item 10.

  Directors, Executive Officers and Corporate Governance      209   

Item 11.

  Executive Compensation      216   

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      240   

Item 13.

  Certain Relationships and Related Transactions, and Director Independence      242   

Item 14.

  Principal Accountant Fees and Services      245   
  PART IV   

Item 15.

  Exhibits and Financial Statement Schedules      245   

Signatures

     247   

In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We refer to our general partner, Enbridge Energy Company, Inc., as our “General Partner.”

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 the Partnership’s 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 or the supply of, forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and NGLs, including the rate of development of the Alberta Oil Sands; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (5) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B and any additional fines and penalties assessed in connection with the crude oil release on that line; (6) changes in or challenges to our tariff rates; (7) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (8) permitting at federal, state and local levels in regards to the construction of new assets.

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

 

i


Table of Contents

Glossary

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

 

AEDC

   Allowance for equity during construction

AER

   Alberta Energy Regulator

AFUDC

   Allowance for funds used in construction

Alberta Clipper Pipeline

   A 36-inch pipeline that runs from the Canadian international border near Neche, North Dakota to Superior, Wisconsin on our Lakehead system

Anadarko system

   Natural gas gathering and processing assets located in western Oklahoma and the Texas Panhandle which serve the Anadarko basin; inclusive of the Elk City System

AOCI

   Accumulated other comprehensive income

Bbl

   Barrel of liquids (approximately 42 United States gallons)

Bcf/d

   Billion cubic feet per day

BLLP

   Beaver Lodge Loop Project

Bpd

   Barrels per day

Btu

   British thermal units

CAA

   Clean Air Act of 1970, as amended

CAD

   Amount denominated in Canadian dollars

CAO

   Corrective Action Order

CAPP

   Canadian Association of Petroleum Producers, a trade association representing a majority of our Lakehead system’s customers

CERCLA

   Comprehensive Environmental Response, Compensation, and Liability Act

CFTC

   Commodity Futures Trading Commission

CO2e

   Carbon Dioxide Equivalent

Credit Facilities

   364-Day Credit Facility and the Credit Facility

CWA

   Clean Water Act

DBRS

   Dominion Bond Rating System

DCF

   Discounted Cash Flow

DOE

   United States Department of Energy

DOJ

   United States Department of Justice

DOT

   United States Department of Transportation

EA interests

   Partnership interests of the OLP related to all the assets, liabilities and operations of the Eastern Access Projects

East Texas system

   Natural gas gathering, treating and processing assets in East Texas that serve the Bossier trend and Haynesville shale areas. Also includes a system formerly known as the Northeast Texas system

Eastern Access Joint Funding Agreement

  

The funding agreement between Enbridge Energy Partners, L.P. (the Partnership) and Enbridge Energy Company, Inc. (the General Partner) to provide joint funding for the Eastern Access Projects

Eastern Access Projects

   Multiple expansion projects that will provide increased access to refineries in the United States Upper Midwest and in Canada in the provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States.

EBITDA

   Earnings Before Interest, Taxes, Depreciation and Amortization

EDA

   Equity Distribution Agreement

EES

   Enbridge Employee Services Inc., a subsidiary of our General Partner

EIA

   Energy Information Administration

Elk City system

   Elk City natural gas gathering and processing system located in western Oklahoma in the Anadarko basin

Enbridge

   Enbridge Inc., of Calgary, Alberta, Canada, the ultimate parent of the General Partner

 

ii


Table of Contents

Enbridge Management

   Enbridge Energy Management, L.L.C.

Enbridge system

   Canadian portion of the liquid petroleum mainline system

Enbridge Pipelines

   Enbridge Pipelines Inc.

Enterprise Products

   Enterprise Products Partners, L.P.

EOSI

   Enbridge Operational Services, Inc.

EP Act

   Energy Policy Act of 1992

EPA

   Environmental Protection Agency

Exchange Act

   Securities Exchange Act of 1934, as amended

FERC

   Federal Energy Regulatory Commission

FIP

   Federal Implementation Plan

FSM

   Facilities Surcharge Mechanism

GDP

   Gross Domestic Product

General Partner

   Enbridge Energy Company, Inc., the general partner of the Partnership

GHG PSD

   Greenhouse Gas Prevention of Significant Deterioration

HB 500

   House Bill 500

HCDP Plants

   Hydrocarbon dewpoint control facilities

High Prarie

   High Prarie Pipelines L.L.C.

IBES

   Institutional Brokers’ Estimate System

ICA

   Interstate Commerce Act

ISDA®

   International Swaps and Derivatives Association, Inc.

IJT

   International Joint Tariff

IRS

   Internal Revenue Service

i-units

   Special class of our limited partner interests

Lakehead system

   United States portion of the liquid petroleum mainline system

LIBOR

   London Interbank Offered Rate—British Bankers’ Association’s average settlement rate for deposits in United States dollars

Light Oil Market Access Program

  

Several projects that will provide increased pipeline capacity on our North Dakota regional system, further expand capacity on our U.S. mainline system, upsize the Eastern Access Project, enhance Enbridge’s Canadian mainline terminal capacity and provide additional access to U.S. Midwestern refineries

M3

   Cubic meters of liquid = 6.2898105 Bbl

Mainline Expansion Joint Funding Agreement

  

The funding agreement between Enbridge Energy Partners, L.P. (the Partnership) and Enbridge Energy Company, Inc. (the General Partner) to provide joint funding for the U.S. Mainline Expansion projects

Mainline system

   The combined liquid petroleum pipeline operations of our Lakehead system and the Enbridge system, which is a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada

Mcf

   Thousand cubic feet

MDEQ

   Michigan Department of Environmental Quality

MDNRE

   Michigan Department of Natural Resources and Environment

MEP

   Midcoast Energy Partners, L.P.

MEP General Partner

   Midcoast Holdings, L.L.C.

Midcoast Operating

   Midcoast Operating, L.P., the operating subsidiary of MEP

MLP

   Master Limited Partnership

MMBtu/d

   Million British Thermal units per day

MMBbls

   Million Barrels of liquids

MMcf/d

   Million cubic feet per day

Mid-Continent system

   Crude oil pipelines and storage facilities located in the Mid-Continent region of the United States and includes the Cushing tank farm and Ozark pipeline

 

iii


Table of Contents

MOODY’S

   Moody’s Investors Service

NEB

   National Energy Board, a Canadian federal agency that regulates Canada’s energy industry

NGA

   Natural Gas Act of 1938

NGL or NGLs

   Natural gas liquids

NGPA

   Natural Gas Policy Act of 1978

North Dakota system

   Liquids petroleum pipeline gathering system and common carrier pipeline in the Upper Midwest United States that serves the Bakken formation within the Williston basin

North Texas system

   Natural gas gathering and processing assets located in the Fort Worth basin serving the Barnett Shale area

NSPS

   New Source Performance Standards

NTSB

   National Transportation Safety Board

NYSE

   New York Stock Exchange

OCC

   Oklahoma Corporation Commission

Offering

   MEP initial public offering

OLP

   Enbridge Energy, Limited Partnership, also referred to as the Lakehead Partnership

OPA

   Oil Pollution Act

PADD

   Petroleum Administration for Defense Districts

PADD II

   Consists of Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin

PADD III

   Consists of Alabama, Arkansas, Louisiana, Mississippi, New Mexico and Texas

PADD IV

   Consists of Colorado, Idaho, Montana, Utah and Wyoming

PADD V

   Consists of Alaska, Arizona, California, Hawaii, Nevada, Oregon and Washington

Partnership Agreement

   Seventh Amended and Restated Agreement of Limited Partnership of Enbridge Energy Partners, L.P., also referred to as our partnership agreement

Partnership

   Enbridge Energy Partners, L.P. and its consolidated subsidiaries

PHMSA

   Pipeline and Hazardous Materials Safety Administration

PIPES of 2006

   Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006

POL

   Percentage of liquids

Ppb

   Parts per billion

PPI-FG

   Producer Price Index for Finished Goods

PSA

   Pipeline Safety Act of 1992

ROE

   Return on Equity

SAGD

   Steam assisted gravity drainage

S&P

   Standard & Poor’s

SEC

   United States Securities and Exchange Commission

SEP II

   System Expansion Program II, an expansion program on our Lakehead system

Series AC interests

   Partnership interests of the OLP related to all the assets, liabilities and operations of the Alberta Clipper Pipeline

Series LH interests

   Partnership interests of the OLP related to all the assets, liabilities and operations of the Lakehead System, excluding those designated by the Series AC interests

Series ME interests

   Partnership interests of the OLP related to all the assets, liabilities and operations of the U.S. Mainline Expansion projects

SIP

   Texas State Implementation Plan

SO2

   Sulfur Dioxide

SORA

   Submerged Oil Recovery and Assessment workplan

Southern Access

   Southern Access Pipeline, a 42-inch pipeline that runs from Superior, Wisconsin to Flanagan, Illinois on our Lakehead system

 

iv


Table of Contents

Suncor

   Suncor Energy Inc., an unrelated energy company

Syncrude

   Syncrude Canada Ltd., an unrelated energy company

Tariff Agreement

   A 1998 offer of settlement filed with the FERC

TRRC

   Texas Railroad Commission

TSX

   Toronto Stock Exchange

UBTI

   Unrelated Business Taxable Income

U.S. GAAP

   United States Generally Accepted Accounting Principles

U.S. Mainline Expansion projects

  

Multiple projects that will expand access to new markets in North America for growing production from western Canada and the Bakken Formation

projects

   production from western Canada and the Bakken Formation

VOC

   Volatile Organic Compound

WCSB

   Western Canadian Sedimentary Basin

 

v


Table of Contents

PART I

Item 1.    Business

OVERVIEW

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

The following chart shows our organization and ownership structure as of December 31, 2014. The ownership percentages referred to below illustrate the relationships between us, Enbridge Energy Management, L.L.C., or Enbridge Management, Enbridge Energy Company, Inc., or our General Partner, and Enbridge Inc., or Enbridge, and its affiliates:

 

LOGO

 

1


Table of Contents

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

We are a geographically and operationally diversified partnership consisting of interests and assets that provide midstream energy services. As of December 31, 2014, our portfolio of assets included the following:

 

   

Our Lakehead system spans a distance of approximately 2,211 miles and consists of approximately 5,300 miles of crude oil pipelines and 75 crude oil storage tanks with an aggregate capacity of approximately 15.5 million barrels;

 

   

Our North Dakota crude oil system is approximately 847 miles long and includes multiple delivery points and crude oil storage facilities with an aggregate working storage capacity of approximately 1.8 million barrels;

 

   

Our Mid-Continent system is comprised of our Ozark crude oil pipeline and storage terminals at Cushing, Oklahoma and Flanagan, Illinois and includes approximately 1,666 miles of crude oil pipelines and 21.4 million barrels of crude oil storage capacity and 108 individual storage tanks ranging in size from 55,000 to 575,000 barrels;

 

   

Approximately 11,100 miles of natural gas gathering and transportation lines and approximately 233 miles of natural gas liquids, or NGL, gathering and transportation lines;

 

   

A 35% interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together own a 593 mile, 20-inch NGL intrastate transportation pipeline extending from the Texas Panhandle to Mont Belvieu, Texas and a related NGL gathering system that consists of approximately 116 miles of gathering lines;

 

   

18 active natural gas processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants, with a combined capacity of approximately 1.6 billion cubic feet per day, or Bcf/d, including 350 million cubic feet per day, or MMcf/d, provided by our HCDP plants;

 

   

Eight active natural gas treating plants, including three that are leased from third parties, with a total combined capacity of approximately 0.9 Bcf/d;

 

   

Approximately 545 compressors with approximately 792,000 aggregate horsepower, the substantial majority of which are owned by Midcoast Operating, L.P., or Midcoast Operating, and the remainder of which are leased from third parties;

 

   

Marketing assets that provide natural gas supply, transmission, storage and sales services.

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

 

2


Table of Contents

BUSINESS STRATEGY

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

 

  1. Operational excellence

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

 

  2. Expanding our core asset platforms

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

 

  3. Project Execution

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

 

  4. Developing new asset platforms

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

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

 

3


Table of Contents

Liquids

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

 

LOGO

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

In 2014, we transported production from the Western Canadian Sedimentary Basin, or WCSB, and the North Dakota Bakken. Western Canadian crude oil is an important source of supply for the United States. According to the latest available data for 2014 from the United States Department of Energy’s, or DOE, Energy Information Administration, or EIA, Canada supplied approximately 2.8 million barrels per day, or Bpd, of crude oil to the United States, the largest source of United States imports. Over half of the Canadian crude oil moving into the United States was transported on the Mainline system. The Canadian Association of Petroleum Producers, or CAPP, forecasts as of June 2014 that future production from the Alberta oil sands will continue to experience steady growth during the next two decades with an additional 2.7 million Bpd of production by 2030, based on a subset of currently approved applications and announced expansions. We are well positioned to deliver growing volumes of crude oil that are expected from the WCSB to our existing as well as new markets.

North Dakota, Montana and Saskatchewan, Canada continued to experience tremendous growth in the development of crude oil, natural gas, and NGLs from the Bakken and Three Forks formations. The latest data released in 2013 by the United States Geological Survey estimated that technically recoverable oil in the Bakken and Three Forks formation in North Dakota have doubled to approximately 7.4 billion barrels.

 

4


Table of Contents

Along with Enbridge, we are actively working with our customers to develop transportation options that will alleviate capacity constraints in addition to providing access to new markets in the United States. Our market strategy is to provide safe, timely, economic, competitive, integrated transportation solutions to connect growing supplies of North American crude oil production to key refinery markets in the United States and Canada. Our strategy also includes further development of our transportation infrastructure to address the growing production of North Dakota and western Canada light oil. Together, our existing and future plans advance our vision of being the leading energy delivery company in North America. In addition to this vision, we have advanced our Operational Risk Management Program. It includes a state-of-the-art Liquids Pipelines control center and the most extensive maintenance, integrity and inspection program in the history of the North American pipeline industry, with 792 in-line inspections and 11,477 pipeline integrity verification digs completed by Enbridge and us from 2010 through 2014.

In 2014, we and Enbridge announced the Line 3 Replacement project. That project, along with the previously announced Eastern Access, Light Oil Market Access and Mainline Expansion projects, will provide increased market access for producers to refineries in the United States upper-Midwest, Eastern Canada, and the United States Gulf Coast refining centers. The Sandpiper project, which was announced in late 2013, complements our current Eastern Access and Light Oil Market Access initiatives.

Eastern Access

Our jointly-funded Eastern Access initiative is comprised of expansion projects that provide both heavy and light crude oil producers with increased market access to the eastern Midwest and eastern Canadian refining markets. In 2013, we expanded Lines 5 and 62, and began the Line 6B replacement program. In September 2014, we completed the final 50 miles of our Line 6B replacement project, which replaced segments of the line from Ortonville, Michigan to St. Clair River, Michigan near the international border, adding 260,000 Bpd of capacity for a total of 500,000 Bpd.

In addition to the above expansions, in 2013 Enbridge completed the reversal of a portion of its Line 9A in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario to serve refineries in that province. Following an open season held on the Line 9B reversal project, further commitments were received that required additional delivery capacity within Ontario and Quebec, resulting in the Line 9 capacity expansion project. The Line 9 capacity expansion will increase the annual capacity of Line 9B from 240,000 Bpd to 300,000 Bpd. Both the Line 9B reversal and Line 9 capacity expansion projects were approved by the Canadian National Energy Board, or NEB, in March 2014 subject to 30 conditions. In October 2014, the NEB requested additional information regarding one of the conditions imposed on the Line 9B reversal and Line 9 capacity expansion projects. On October 23, 2014, Enbridge responded to the NEB describing the Enbridge’s rigorous approach to risk management and isolation valve placement. On February 6, 2015, the NEB approved two conditions from its previous order and Enbridge filed for the Leave to Open from the NEB. Enbridge expects to place the Line 9B reversal and Line 9 expansion project into service in the second quarter of 2015. As a condition of the February 2015 approval, the NEB also imposed additional obligations to ensure optimal protection of the area’s water resources. These projects will enable growing light crude production from the Bakken shale and from Alberta to meet refinery needs in Michigan, Ohio, Ontario and Quebec. These projects will also provide much needed transportation outlets for light crude, mitigating the current discounting of supplies in the basins, while also providing more favorable supply costs to refiners currently dependent on crudes priced off of the Atlantic basin.

Light Oil Market Access

To accommodate the significant and sustainable growth in the Bakken resource play, we, along with our 37.5% funding partner and anchor shipper, Marathon Petroleum Corporation, are proposing to construct the approximately 600-mile Sandpiper pipeline. The pipeline will carry an additional 225,000 Bpd to Clearbrook, Minnesota and 375,000 Bpd to Superior, Wisconsin. We have received Federal Energy Regulatory Commission,

 

5


Table of Contents

or FERC, approval for the commercial rate structure and now require approval from the Minnesota Public Utilities Commission and the State of Wisconsin to begin construction. The Sandpiper pipeline is a key pipeline that will supply numerous other downstream pipeline expansions and new construction funded by either Enbridge or us, or both, and is targeted to be in service in 2017. We, along with Enbridge, will twin Line 62 with Line 78, which will add 570,000 bpd of new pipeline capacity between Flanagan, Illinois and Griffith, Indiana by the third quarter of 2015. Furthermore, we and Enbridge will expand the replaced Line 6B capacity to 570,000 Bpd in 2016. The Enbridge-funded Southern Access Extension, Line 9 reversal and other expansion projects will also increase the markets accessed by Lakehead and drive volumes through the Lakehead system. Enbridge’s 165-mile, 24-inch diameter Southern Access Extension pipeline from Flanagan, Illinois to Patoka, Illinois will add 300,000 bpd into the Patoka terminal in 2015.

In North Dakota, oil production levels grew to an approximate average of 1.1 million Bpd during 2014. Capitalizing on this growth, our Berthold Rail Project allows Bakken crude oil further access to markets that are not connected to the major Midwest pipelines. For further discussion on these projects see BUSINESS SEGMENTS—North Dakota System in this Item.

Mainline Expansions

To support these expansions, we and Enbridge have also announced projects to increase Enbridge Mainline capacity, which are to be constructed in three phases. Phase 1 includes increasing the capacity on our Southern Access pipeline, or Line 61, from 400,000 Bpd to 560,000 Bpd and an expansion to Alberta Clipper, or Line 67, capacity from 450,000 Bpd to 570,000 Bpd, both of which were completed during 2014. Phase 2 of the Mainline Expansions consists of further expansions, over time, to Line 61. This phase will be split into two tranches. The first tranche will expand Line 61’s pipeline capacity to 800,000 Bpd and is expected to be in service in the second quarter of 2015. Additional tankage is expected to be completed on various dates beginning in the second quarter of 2015 through early 2016. The second tranche, which remains subject to regulatory and other approvals, will expand the pipeline capacity to 1,200,000 Bpd. Management is exploring with shippers the potential to delay the in-service date of the final tranche of the Line 61 expansion to align more closely with the currently anticipated in-service date for the Sandpiper project, which will drive the need for additional downstream capacity. Lastly, Phase 3 of the Mainline Expansions also includes further expansions Line 67, from 570,000 Bpd to 800,000 Bpd in the second half of 2015.

Line 3 Replacement

Earlier in 2014, we and Enbridge announced our plans to undertake the Line 3 Replacement project, with a focus on increasing system reliability and flexibility. Enbridge will replace portions of Line 3 that run from Enbridge’s Hardisty, Alberta terminal to Gretna, Manitoba in Canada. Additionally, we will replace portions from the international border near Neche, North Dakota to Superior, Wisconsin. The replacement of Line 3 from Gretna, Manitoba to Superior Wisconsin will be jointly funded between us and Enbridge. The total capital investment from us for replacing portions of Line 3 from Neche, North Dakota to Superior Wisconsin is approximately $2.6 billion. This project has CAPP support, and is expected to be completed during late 2017.

Enbridge Projects

A key competitive strength of ours is our relationship with Enbridge. Enbridge is constructing two additional major United States Gulf Coast market access pipeline projects that will pull more volume through the Lakehead system.

The Flanagan South Pipeline is a twinning of the Spearhead system, and transports increased volumes from Flanagan, Illinois into the Cushing, Oklahoma hub. The 36-inch diameter pipeline has a capacity of approximately 600,000 Bpd, and the pipeline was placed in service in December 2014.

 

6


Table of Contents

In January 2013, Enbridge and its joint venture partner Enterprise Products Partners, L.P., or Enterprise Products, expanded the capacity of their jointly owned Seaway Crude Pipeline System, or Seaway pipeline, to approximately 400,000 Bpd, depending upon the mix of light and heavy grades of crude oil. The Seaway system serves the Houston, Texas City and Freeport refining complexes. A new parallel twin to the Seaway pipeline was mechanically complete in July of 2014 with line fill completed in December 2014, which added 450,000 Bpd of capacity to the system. Additionally, the joint venture between Enbridge and Enterprise Products constructed a 100-mile pipeline from Enterprise Product’s ECHO crude oil terminal southeast of Houston, Texas to the Port Arthur/Beaumont, Texas refining center, referred to as the Seaway Lateral, which will move crude oil from the Seaway pipeline into the refining market east of Houston, Texas.

Enbridge is reviewing a potential restructuring plan that may involve the sale of some of its directly held U.S. liquids pipeline assets to us. Any such transfer of directly held Enbridge U.S. liquids pipeline assets represents several possible opportunities and impacts for our new and existing systems. Enbridge’s review of the potential restructuring plan, however, is still underway and has not progressed to a conclusion. Thus, there can be no assurance that any such restructuring will occur.

Natural Gas

The map below presents the locations of our current Natural Gas systems assets’ and projects being constructed, including joint ventures. These assets are owned by Midcoast Energy Partners, L.P., or MEP, and its subsidiaries. MEP is a Delaware limited partnership we formed to serve as our primary vehicle for owning and growing our natural gas and NGL midstream business in the United States. MEP completed its initial public offering, or the Offering, in November of 2013, but we continue to own all of the equity interests in MEP’s general partner, a 52% limited partner interest in MEP and a 48.4% limited partner interest in MEP’s operating subsidiary, Midcoast Operating. This map depicts some assets owned or under development by Enbridge to provide an understanding of how they relate to our Natural Gas systems.

 

LOGO

 

7


Table of Contents

Our natural gas assets are primarily located in Texas and Oklahoma, a region which continues to maintain its status as one of the most active natural gas producing areas in the United States. Our three systems in Texas are located in basins that have experienced active drilling over the last several years. These core basins are known as the East Texas basin, the Fort Worth basin and the Anadarko basin. Our focus has primarily been on developing and expanding the service capability of our existing pipeline systems and acquiring assets with strong growth prospects located in or near the areas we serve or have competitive advantage. We may also target future growth in areas where we can deploy our successful operating strategy to expand our portfolio into other natural gas production regions.

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

The long term prospects in our core areas remain favorable, primarily as a result of technological advancements that have enhanced production of natural gas and NGLs from tight sand and shale formations. The reserves and resource potential in all three of our operating basins is substantial. The current price environment has forced producers to focus their drilling efforts on oil, condensate and liquids rich gas, all of which still produce associated gas that needs to be gathered and requires processing to separate the NGLs. When natural gas prices recover to the level that will incentivize producers to drill their lean gas prospects, our core assets are well positioned to gather, treat and transport this gas to market. To address a near term liquids focused environment, we have increased our gas processing capacity, our NGL takeaway capacity, and third party fractionation capacity at major fractionation hubs. Our goal is to offer our customers the ability to gather, process, and transport their liquids to major markets.

Our Natural Gas business also includes trucking, rail and liquids marketing operations that we use to enhance the value of the NGLs produced at our processing plants. Our Natural Gas marketing business provides us with the ability to maximize the value received for the natural gas we transport and purchase by identifying customers with consistent demand for natural gas.

BUSINESS SEGMENTS

We conduct our business through two business segments:

 

   

Liquids; and

 

   

Natural Gas.

These segments have unique business activities that require different operating strategies. During the first quarter of 2014, we changed our reporting segments. The Marketing segment was combined with the Natural Gas segment to form one new segment called “Natural Gas.” There was no change to the Liquids segment.

This change was a result of our reorganization resulting from the Offering, which prompted management to reassess the presentation of our reportable segments considering the financial information available and evaluated regularly by our Chief Operating Decision Maker. The new segment is consistent with how management makes resource allocation decisions and evaluates performance, and furthers the achievement of our

 

8


Table of Contents

long-term objectives. Financial information for the prior periods has been restated to reflect the change in reporting segments.

For information relating to revenues from external customers, operating income and total assets for each segment, refer to Note 16. Segment Information of our consolidated financial statements.

Liquids Segment

Lakehead system

Our Lakehead system, together with the Enbridge system in Canada, form the Mainline system, which has been in operation for over 60 years and forms the longest liquid petroleum pipeline system in the world. The Mainline system operates in a segregation, or batch, mode allowing the transport of 28 crude oil commodities including light, medium, and heavy crude oil, condensate, and NGLs. The Mainline system serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the province of Ontario, Canada.

The Lakehead system is the U.S. portion of Enbridge Inc.’s Mainline system. It is an interstate common carrier pipeline system regulated by the FERC. Our Lakehead system spans a distance of approximately 2,211 miles and consists of approximately 5,300 miles of pipe with diameters ranging from 12 inches to 48 inches, and is the primary transporter of crude oil and liquid petroleum from Western Canada to the United States. Additionally, the Lakehead system has 66 pump station locations with a total of approximately 1,027,000 installed horsepower and 75 crude oil storage tanks with an aggregate capacity of approximately 15.5 million barrels.

Lakehead throughput volumes are primarily supplied by crude oil produced in the growing Bakken and Canadian oil sands resource plays. Crude oil supply from the Bakken region continues to outperform historical expectations as production now exceeds 1.0 million Bpd. Forecasts of Western Canadian crude oil supply are periodically completed by Enbridge, CAPP and the NEB, among others. Western Canada oil sands production is expected to grow by 2.7 million Bpd to over 4.8 million Bpd by 2030. This compares with an expected increase of only 200,000 Bpd from conventional production sources over the same time frame. CAPP revised its oil sands production forecast downward by 400,000 Bpd in 2014 from 5.2 million Bpd to 4.8 million Bpd due to constraints arising from oil sands cost competitiveness and delays in project schedules. In addition, given the recent reductions in near-term capital expenditures announced by Western Canadian producers, CAPP revised its near-term annual production forecast in 2016 to 2.5 million Bpd, which represents a modest reduction of 56,000 Bpd in the oil sands supply growth forecast for 2016. Despite the revisions, the production growth forecasted out of our primary supply markets requires additional pipeline capacity.

Over the past five years, we have completed the largest pipeline expansion program in our history in order to accommodate the growing upstream supply that will feed our completed downstream market access projects. From 2008 through 2010, we completed the Southern Access expansion program, referred to as the Southern Access Pipeline, or Line 61, which increased the capacity of our Mainline system into the Chicago area by 400,000 Bpd and the Alberta Clipper expansion program, referred to as the Alberta Clipper Pipeline, or Line 67, which added 450,000 Bpd of additional capacity into Superior. Subject to regulatory approvals, we intend to expand the Southern Access Pipeline further to a total capacity of 1.2 million Bpd with additional pumping station capital. Similarly, we intend to expand, subject to regulatory approvals, the U.S. portion of the Alberta Clipper Pipeline further to 800,000 Bpd.

Our customers have long development timelines and need assurance that adequate pipeline infrastructure will be in place in time to transport the additional production resulting from completion of their projects. The projects included in our Eastern Access, Light Oil Market Access, U.S. Gulf Coast access, and associated Mainline/Lakehead expansion initiatives will provide the needed incremental market access for both our producer and refiner customers located in our primary target markets.

 

9


Table of Contents

Customers.    Our Lakehead system operates under month-to-month transportation arrangements with our shippers. During 2014, approximately 56 shippers tendered crude oil and liquid petroleum for delivery through our Lakehead system. We consider multiple companies that are controlled by a common entity to be a single shipper for purposes of determining the number of shippers delivering crude oil and liquid petroleum on our Lakehead system. Our customers include integrated oil companies, major independent oil producers, refiners and marketers.

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

Crude oil originating from the WCSB comprises the majority of Lakehead system deliveries. According to the Energy Information Administration, or EIA, Canada is currently ranked third in the world for total proved reserves, just behind Saudi Arabia and Venezuela, respectively. The NEB estimates that 98% of Canada’s total proved reserves are attributed to Alberta’s oil sands bitumen, with the remainder being conventional oil sources. The Alberta Energy Regulator, or AER, estimates 169 billion total barrels, or approximately 167.2 billion and 1.8 billion barrels of established proved bitumen and conventional reserves, respectively, remain for the region as of 2014. The NEB estimates that total production from the WCSB in 2014 averaged approximately 3.6 million Bpd in 2014 and 3.3 million in 2013. Furthermore, these production levels are expected to grow in the future, as previously discussed.

The growth forecast in the oil sands is being primarily driven by steam assisted gravity drainage, or SAGD, projects. Based on projects currently under construction in Western Canada, the incremental productive capacity that would have access to our systems is reported to increase over the next three years by approximately 1.0 million Bpd.

North Dakota’s Bakken resource play has grown dramatically since 2010, and has become a major component of United States domestic supply. Crude oil supply from the region continues to outperform historical expectations as production averaged approximately 1.0 million Bpd in 2014.

Our Lakehead system is strategically interconnected to multiple refining centers and transportation hubs located within Petroleum Administration for Defense Districts, or PADD, II such as: Chicago, Illinois; Patoka, Illinois; and Cushing, Oklahoma. PADD II is the primary demand market for our Lakehead system. Deliveries on our Lakehead system are negatively affected by periodic maintenance, other competitive transportation alternatives, or refinery turnarounds and other shutdowns at producing plants that supply crude oil. Based on growth in Western Canadian and Bakken crude oil supply and Lakehead operational performance improvements, deliveries on our Lakehead system are expected to grow beyond the 2.1 million Bpd of actual deliveries experienced during 2014.

The latest data available from the EIA extends through October 2014 and shows that total PADD II demand was 3.5 million Bpd. PADD II produced 1.6 million Bpd, and thus imported 1.9 million Bpd from Canada and other regions located in the United States. Imports from Canada comprised 98% of total PADD II crude oil imports, with approximately 74% or 1.4 million Bpd transported on our Lakehead system. The remaining barrels were imported via competitor pipelines from Alberta and offshore sources via the U.S. Gulf Coast or regional transfers from PADD III or PADD IV. Lakehead system deliveries for 2014 were approximately 297,000 Bpd higher than delivery volumes for 2013. Total deliveries from our Lakehead system averaged 2.1 million Bpd in 2014, meeting approximately 84% of the refinery capacity in the greater Chicago area; 76% of the Minnesota refinery capacity; and 83% of Ontario refinery capacity.

 

10


Table of Contents

Refinery configurations and crude oil requirements within PADD II continue to create an attractive market for Western Canadian and Bakken supply. According to the latest data from the EIA covering January through September 2014, overall refining utilization for PADD II rose 3.5%. Crude oil demand in PADD II averaged 3.5 million Bpd, an increase of 138,000 Bpd from 2013. The primary driver of the increase in PADD II demand is attributed to the completion of BP’s modernizing project at its Whiting, Indiana refinery. The project was completed in the first quarter of 2014.

Competition.    WCSB production in excess of Western Canadian demand moves on existing pipelines into primarily PADD II, with secondary markets including: the Rocky Mountain states (PADD IV); the Anacortes area of Washington state (PADD V); the U.S. Gulf Coast (PADD III); and to Eastern Canada (Ontario). In each of these regions, WCSB crude oil competes with local and imported crude oil. Of all the pipeline systems that transport crude oil out of Canada, the Mainline system transported approximately half of all Canadian crude oil imports into the United States in 2014.

The Lakehead system mainly serves the PADD II market directly and the PADD III market indirectly. Bakken production in excess of local demand primarily moves on existing pipelines into PADD II or is transported by rail to coastal Canadian and U.S. refining markets. The U.S. Gulf Coast continues to be an attractive market for WCSB producers due to the market’s large refining capacity designed to process heavy crude oil. The forecasted long-term incremental growth of Canadian oil sands and Bakken production provides stability for existing pipeline throughputs to historical markets as well as creating new growth opportunities available to both us and our competitors.

Our Eastern Access, Light Oil Market Access, U.S. Gulf Coast Access, and associated Mainline expansion projects will improve the flexibility of our system and are designed to increase Lakehead throughput by reaching new markets. Given the expected increase in crude oil production from the Alberta Oil Sands over the next 10 years, alternative transportation proposals have been presented to crude oil producers. Competitors’ proposals to WCSB and Bakken shippers include expanding, twinning, extending and building new pipeline assets. These proposals and projects are in various stages of regulatory approval. The following provides an overview of other proposals and projects put forth by competing pipeline companies that are not affiliated with Enbridge:

 

   

In 2008, commercial support was announced to construct Keystone XL, a 36-inch crude oil pipeline that will begin at Hardisty, Alberta and extend down to Cushing, Oklahoma, and then to Nederland, Texas. The pipeline will connect to existing crude oil pipeline from Hardisty, Alberta to Wood River and Patoka, Illinois. Construction of the pipeline will add an additional 700,000 Bpd of capacity when completed. However, in early 2012, the U.S. government rejected the necessary permits for the project as it is currently proposed, thereby making the future of this project uncertain. The project sponsor reapplied for the necessary permits; however, the project is still awaiting presidential approval and no timeline has been set for a decision.

 

   

In 2012, strong binding commercial support was announced for the expansion of the existing crude oil pipeline transportation services between Alberta and British Columbia. The expansion is comprised of pipeline facilities that may complete the looping of the pipeline in Alberta and British Columbia, pumping stations, tanks in Edmonton and Burnaby and expansion of the Westridge Marine Terminal, with a planned in service date in early 2017. The pipeline has a current capacity of 300,000 Bpd with expansion alternatives up to 890,000 Bpd. The company submitted a formal application to the NEB on December 16, 2013.

 

   

In 2013, a successful open season was announced for a pipeline project to transport Western Canadian volume to Eastern Canada, confirming strong market support for the pipeline. The project is expected to provide 1.1 million Bpd of crude oil transportation service from Western to Eastern Canada. The project sponsor has not yet made a formal application for the project; however, they have stated that the expected in service date is in late 2018.

 

11


Table of Contents
   

In 2014, an open season was announced for a pipeline project to transport crude oil from the Bakken/Three Forks production area in North Dakota to key refinery and terminal hubs in the Midwest and Gulf Coast. The project currently has a planned capacity of 320,000 Bpd and is seeking additional commitments to expand capacity to a total amount in excess of 450,000 Bpd. The project is expected to commence commercial operations in the fourth quarter of 2016.

 

   

In 2014, commercial service began on a 230,000 Bpd, 690-mile pipeline that transports light crude oil found in the Bakken production area from Guernsey, Wyoming, to multiple delivery locations in and around Cushing, Oklahoma.

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

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

 

     2014      2013      2012      2011      2010  
     (thousands of Bpd)  

United States

              

Light crude oil

     496        473        521        473        458  

Medium and heavy crude oil

     1,167        948        879        850        841  

NGL

     6        6        5        4        3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total United States

     1,669        1,427        1,405        1,327        1,302  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Ontario

              

Light crude oil

     298        247        228        220        223  

Medium and heavy crude oil

     72        76        85        84        57  

NGL

     74        66        72        69        73  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Ontario

     444        389        385        373        353  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Deliveries

     2,113        1,816        1,790        1,700        1,655  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Barrel miles (billions per year)

     582        487        480        450        439  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Mid-Continent system

Our Mid-Continent system, which we have owned since 2004, is located within PADD II and is comprised of our Ozark pipeline and storage terminals at Cushing, Oklahoma and Flanagan, Illinois. Our Mid-Continent system includes approximately 1,666 miles of crude oil pipelines and approximately 21.4 million barrels of crude oil storage capacity. Our Ozark pipeline transports crude oil from Cushing to Wood River, where it delivers to the Phillips 66 refinery located at Wood River, Illinois and interconnects with the Woodpat Pipeline and the Wood River Pipeline, each owned by unrelated parties.

The storage terminals consist of 108 individual storage tanks ranging in size from 55,000 to 575,000 barrels. In 2014, approximately 0.9 million barrels of incremental shell capacity came into service. Of the approximately 21.4 million barrels of storage shell capacity on our Mid-Continent system, the Cushing, Oklahoma terminal accounts for approximately 20.1 million barrels. A portion of the storage facilities are used for operational purposes, while we contract the remainder of the facilities with various crude oil market participants for their term storage requirements. Contract fees include fixed monthly capacity fees as well as utilization fees, which we charge for injecting crude oil into and withdrawing crude oil from the storage facilities.

 

12


Table of Contents

Customers.    Our Mid-Continent system operates under month-to-month transportation arrangements and both long-term and short-term storage arrangements with its shippers. During 2014, approximately 53 shippers tendered crude oil for service on our Mid-Continent system. We consider multiple companies that are controlled by a common entity to be a single shipper for purposes of determining the number of shippers delivering crude oil and liquid petroleum on our Mid-Continent system. These customers include integrated oil companies, independent oil producers, refiners and marketers. Average deliveries on the Ozark pipeline system were 200,000 Bpd for 2014 and 201,000 Bpd for 2013.

Supply and Demand.    Our Mid-Continent system is positioned to capitalize on increasing demand for both domestic and imported crude oil, specifically Canadian imports into the United States. In addition, the Cushing terminal remains in high demand as a result of superior connectivity and robust amounts of trading. In 2014, PADD II imported 1.9 million Bpd from outside of the PADD II region, the majority of which were imported from Canada primarily on our Lakehead system. The remaining barrels of crude oil were imported from PADDs III and IV as well as offshore sources. We expect the demand for local supply to increase and the demand for Canadian crude to stay strong, thus displacing the necessity for other foreign sources.

Competition.    Our Ozark pipeline system currently serves an exclusive corridor between Cushing, Oklahoma and Wood River, Illinois. However, refineries connected to Wood River have crude oil supply options available from Canada via our Lakehead system and a third party pipeline. These same refineries also have access to the United States Gulf Coast and foreign crude oil supply through a third-party pipeline system, which is an undivided joint interest pipeline that is owned by unrelated parties. In addition, refineries located east of Patoka with access to crude oil through our Ozark system, also have access to west Texas supply through the West Texas Gulf/Mid-Valley Pipeline systems owned by unrelated parties. Our Ozark pipeline system faces a significant increase in competition after the completion of a competitor’s pipeline from Hardisty, Alberta to Patoka, Illinois that came into service in June 2010. Our Ozark pipeline system provides crude oil types and grades that are generally lighter and with lower sulfur relative to that transported on the competitor’s pipeline. To date, our Ozark system has remained full. If a negative impact does occur to the volumes on our Ozark system, we will consider alternative uses for our Ozark system.

In addition to movements into Wood River, Illinois, crude oil in Cushing, Oklahoma is transported to Chicago, Illinois and the U.S. Gulf Coast on lines partially owned by Enbridge and on third-party pipeline systems. Western Canadian crude oil moving on Spearhead to Cushing, Oklahoma continues to increase the importance of Cushing as a terminal and pipeline origination area.

The storage terminals rely on demand for storage service from numerous oil market participants. Producers, refiners, marketers and traders rely on storage capacity for a number of different reasons: batch scheduling, stream quality control, inventory management, and speculative trading opportunities. Competitors to our storage facilities at Cushing, Oklahoma include large integrated oil companies and other midstream energy partnerships. Demand for storage capacity at Cushing, Oklahoma has remained high as customers continue to value the flexibility and optionality available with this service. Competition comes from other storage providers with available land and operational facilities in the area. Competition is driven by reliability, quality of service, connectivity and price.

North Dakota system

Our North Dakota system is a crude oil gathering and interstate pipeline transportation system servicing the Williston Basin in North Dakota and Montana, which includes the highly publicized Bakken and Three Forks formations. Our North Dakota system is approximately 847 miles long, has 23 pump stations, multiple delivery points and storage facilities with an aggregate working storage capacity of approximately 1.8 million barrels, and the gathering pipelines that comprise our North Dakota system collect crude oil from nearly 100 different receipt facilities located throughout western North Dakota and eastern Montana, including nearly 20 third party gathering pipeline connections, and deliver a fungible common stream to a variety of interconnecting pipeline and rail export facilities.

 

13


Table of Contents

Traditionally, the majority of our pipeline deliveries have been made into interconnecting pipelines at Clearbrook, Minnesota where two other pipelines originate: (1) a third-party pipeline serving St. Paul, Minnesota refinery markets; and (2) our Lakehead system providing further pipeline transportation on the Enbridge system into the Great Lakes, eastern Canada and U.S. Midwest refinery markets that include Cushing, Patoka and other pipelines delivering crude oil to the US Gulf Coast. Today, our North Dakota System continues to serve these traditional markets, but through a series of projects in recent years, we have significantly increased the pipeline and rail export capacity from 80,000 Bpd in 2005 to more than 650,000 Bpd in 2014 while providing an array of market options and services:

 

   

North Dakota Classic—Our Phase 5 and Phase 6 Expansions, coupled with a series of other optimization efforts, have increased the pipeline capacity on our traditional North Dakota system to approximately 210,000 Bpd. The North Dakota Classic system originates at Alexander Station in McKenzie County and terminates at our delivery station at Clearbrook, Minnesota.

 

   

Bakken Pipeline Expansion—In March 2013, the Bakken Pipeline Expansion Project was placed into service providing an additional 145,000 Bpd of pipeline export capacity from North Dakota. This project, a joint crude oil pipeline expansion project with Enbridge Income Fund Holdings Inc., a partially-owned subsidiary of Enbridge, originates at Berthold, North Dakota and terminates at the Enbridge Mainline in Cromer, Manitoba. Enbridge has secured long term volume commitments from multiple shippers for 100,000 Bpd of the 145,000 Bpd of capacity. The terms of these contracts are 5 or 10 years, with the majority of the volumes contracted at 10 years. The Bakken Expansion Project includes a 225,000 Bpd expansion of the North Dakota Classic system, the Beaver Lodge Loop Project, or the BLLP, which provides 425,000 Bpd of pipeline capacity into Berthold Station. The BLLP was also placed into service in March 2013.

 

   

Bakken Access Program—During 2013, we completed the pipeline station expansion projects and third-party pipeline connections that were announced in October 2011 as the Bakken Access Program. This Bakken Access program substantially enhanced our gathering capabilities on the North Dakota system and included new facilities at multiple locations accommodating seven third party pipeline connections and the construction of the Little Muddy Station, a new truck delivery/gathering pipeline facility strategically located in Williams County, North Dakota. Our North Dakota system now has the ability to receive more than 500,000 Bpd from third-party pipelines and more than 600,000 Bpd from Enbridge truck and gathering facilities.

 

   

Berthold Rail Project—In March 2013, Berthold Rail was placed into service with an 80,000 Bpd capacity, providing our North Dakota customers with an alternative transportation solution to shipper needs in the Bakken region. Today, Berthold Rail feeds Bakken crude to U.S. West Coast, U.S. Gulf Coast and U.S. East Coast markets and provides an excellent complement to the options and market access available to Enbridge customers. The facility includes 150,000 barrels of operational storage.

 

   

Berthold Storage—From October 2013 to March 2014, Enbridge Storage (North Dakota) placed two 150,000 contract storage tanks into service at its merchant storage facility located adjacent to Berthold Station and the Berthold Rail Project. At Berthold, ESND has an ultimate capacity of 300,000 barrels of total storage capacity.

 

   

Sandpiper Pipeline Project—In November 2013, Enbridge and Marathon Petroleum announced the joint development of the Sandpiper Pipeline Project and the creation of the North Dakota Pipeline Company. Sandpiper is an approximate 600-mile pipeline project originating at Beaver Lodge Station near Tioga, North Dakota and terminating at Enbridge’s Superior, Wisconsin facilities. The portion from Beaver Lodge to Berthold, North Dakota will add 250,000 Bpd of capacity and the portion from Berthold, North Dakota to Clearbrook, Minnesota will add 225,000 Bpd of capacity, with both being 24-inch pipelines. Additionally, the portion from Clearbrook to Superior will be a 30-inch pipeline with 375,000 Bpd of capacity.

 

14


Table of Contents

Customers.    Customers of our North Dakota system include refiners of crude oil, producers of crude oil and purchasers of crude oil at the wellhead, such as marketers, that require crude oil gathering and transportation services. Producers range in size from small independent owner/operators to large integrated oil companies. During 2014, approximately 148 shippers tendered crude oil for service on our North Dakota system.

Supply and Demand.    Similar to our Lakehead system, our North Dakota system depends upon demand for crude oil in the Great Lakes and Midwest regions of the United States and the ability of crude oil producers to maintain their crude oil production and exploration activities. Due to increased exploration of the Bakken and Three Forks formations within the Williston Basin, the state of North Dakota reported production levels of 1.2 million Bpd as of October 2014 with projections of stabilizing at that level or growing at a low rate due to low oil prices.

Competition.    Traditional competitors of our North Dakota system include refiners, integrated oil companies, interstate and intrastate pipelines or their affiliates and other crude oil gatherers. Many crude oil producers in the oil fields served by our North Dakota system have alternative gathering facilities available to them or have the ability to build their own assets, including their own rail loading facilities. There are a number of third-party pipelines with proposed expansions to increase their capacities to take advantage of the Bakken and Three Forks volume growth: many of these third party pipeline projects are including pipeline connections into our North Dakota system as part of their project scope.

The chief transportation competition to our North Dakota system is rail. Initially considered a niche or alternative form of transportation, rail currently represents more than 59% of the total Bakken crude exported from North Dakota. Rail provides some advantages to pipeline transportation, but future Enbridge pipeline expansions and enhanced market access to Eastern Canadian markets and eastern PADD II are reducing these advantages when it comes to shipping alternatives. As pipeline expansion projects create more export capacity from the Bakken and other pipeline projects provide increased access to more refinery markets across the United States, we expect North Dakota customers will shift volumes back to pipelines.

Natural Gas Segment

Our natural gas business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities and NGL fractionation facilities, as well as trucking, rail and liquids marketing operations. We gather natural gas from the wellhead and central receipt points on our systems, deliver it to our facilities for processing and treating and deliver the residue gas to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies. We deliver the NGLs produced at our processing and fractionation facilities to intrastate and interstate pipelines for transportation to the NGL market hubs in Mont Belvieu, Texas and Conway, Kansas. In addition, using the Texas Express NGL system, we gather NGLs from certain of our facilities for delivery on the Texas Express NGL mainline to Mont Belvieu, Texas. These assets are owned by MEP and its subsidiaries. MEP is a Delaware limited partnership we formed to serve as our primary vehicle for owning and growing our natural gas and NGL midstream business in the United States. MEP completed its initial public offering in November of 2013, but we continue to own all of the equity interests in MEP’s general partner, a 52% limited partner interest in MEP and a 48.4% limited partner interest in MEP’s operating subsidiary, Midcoast Operating.

Our natural gas business consists of the following four systems:

 

   

Anadarko system:    Approximately 3,100 miles of natural gas gathering and transportation pipelines, approximately 60 miles of NGL pipelines, seven active natural gas processing plants, five standby natural gas processing plants and one standby treating plant located in the Anadarko basin.

 

   

East Texas system:    Approximately 4,100 miles of natural gas gathering and transportation pipelines, approximately 144 miles of NGL pipelines, four active natural gas processing plants, including two

 

15


Table of Contents
 

HCDP plants, seven active natural gas treating plants, two standby natural gas treating plants and one fractionation facility located in the East Texas basin.

 

   

North Texas system:    Approximately 3,900 miles of natural gas gathering and transportation pipelines, approximately 29 miles of NGL pipelines, and seven active natural gas processing plants located in the Fort Worth basin.

 

   

Texas Express NGL system:    A 35% interest in an approximately 593-mile NGL intrastate transportation mainline and a related NGL gathering system that consists of approximately 116 miles of gathering lines. The Texas Express NGL system commenced startup operations during the fourth quarter of 2013.

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

Supply and Demand.    Demand for our gathering, processing and transportation services primarily depends upon the supply of natural gas reserves and associated natural gas crude oil development and the drilling rate for new wells. The level of impurities in the natural gas gathered also affects treating services. 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 began declining in the fourth quarter of 2014 and into 2015. As a result, there has been recent reduction in drilling activity by producers. Our existing systems are located in basins that have the opportunity to grow in an improved pricing environment. All of our natural gas systems exist in regions that have shale or tight sands formations where horizontal fracturing technology can be utilized to increase production from the natural gas wells.

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 brought about 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.

We expect development of the Granite Wash play in the Texas Panhandle and western Oklahoma to continue due to the prolific nature of the wells, and to increase when market prices for NGLs and crude oil increase. In order to accommodate the expected growth of the Granite Wash play, we began commissioning the operations of a cryogenic processing plant in the third quarter of 2013, which we refer to as our Ajax processing plant. The Ajax processing plant, condensate stabilizer, field and plant compression, gathering infrastructure and NGL pipelines assist in meeting the anticipated volume growth within our Anadarko system. The total cost of constructing the Ajax processing plant and related facilities was approximately $230.0 million. The Ajax processing plant increased the total processing capacity of our Anadarko system by approximately 150 MMcf/d to approximately 1,150 MMcf/d and also increased the system’s condensate stabilization capacity by approximately 2,000 Bpd. The Ajax processing plant is capable of producing approximately 15,000 Bpd of NGLs now that the Texas Express NGL pipeline, which we refer to as the mainline, is in operation.

 

16


Table of Contents

With recent commodity prices declining we have idled approximately five less efficient processing plants and consolidated volumes to our more efficient plants, such as Ajax. These plants are available for restart when production increases.

Our Anadarko system has numerous market outlets for the natural gas that we gather and process and NGLs and condensate that we recover on our system. We have connections to major intrastate and interstate transportation pipelines that connect our facilities to major market hubs in the Mid-Continent and Gulf Coast regions of the United States. All of our owned residue gas and condensate is sold to our trucking and marketing business. A portion of our owned NGLs is sold directly to a third-party, while the remainder is sold to our trucking 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; 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; and the Eaglebine play, which spans five counties in East Texas and is comprised of multiple drilling zones crossing through the Woodbine and Eagle Ford formations. 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. While dry gas drilling declined with the historical decreases in gas prices, more recently, drilling activity has increased in the basin by customers pursuing rich gas and crude oil formations using horizontal drilling and multistage fracturing. In 2014, our processing plants in East Texas were at full capacity.

In the third quarter of 2013, we initiated construction activities at our Beckville processing plant and the related facilities on our East Texas system. This plant along with our significant processing infrastructure in the region is expected to serve existing and prospective customers pursuing production from formations and plays in the East Texas Basin including the Cotton Valley, James Lime, Eaglebine and other liquid rich opportunities in the area. We expect our Beckville processing plant to be capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs to accommodate the additional liquids-rich natural gas being developed within this geographical area in which our East Texas system operates. We estimate the cost of constructing the plant to be approximately $145.0 million and expect it to commence commercial service early in second quarter of 2015.

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. The majority of our owned residue gas is sold to our trucking and marketing business, while the remainder of our owned residue gas is sold directly to third-party wholesale customers or utilities. All of our owned condensate is sold to our trucking 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 trucking 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

 

17


Table of Contents

with predictable flow rates. Producers are pursuing wells with higher condensate and oil production relative to historical activity due to the relatively lower valued gas prospects. As producers have shifted from dry natural gas drilling to rich gas from crude oil production, we have seen our natural gas volumes decline. However, our NGL and condensate production increased in 2014.

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

Texas Express NGL System

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.

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

Trucking and Marketing Operations

We also include our trucking and marketing operations in our Natural Gas segment. The primary role of our trucking and marketing business is to market natural gas, NGLs and condensate received from our gathering, processing and transportation systems, thereby enhancing our competitive position. In addition, we provide our customers with the opportunity to receive enhanced economics by providing access to premium markets through the transportation capacity and other assets we control. We purchase and receive natural gas, NGLs and other products from pipeline systems and processing plants and sell and deliver them to wholesale customers, such as distributors, refiners, fractionators, utilities, chemical facilities and power plants.

 

18


Table of Contents

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

 

   

Approximately 225 transport trucks, 370 trailers and 190 railcars for transporting NGLs;

 

   

Our TexPan liquids railcar facility near Pampa, Texas; and

 

   

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

 

   

An approximately 40-mile propylene pipeline extending from Exxon’s refinery in Chalmette, Louisiana to an interconnecting Chevron pipeline near Lafitte, Louisiana.

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

 

   

Up to approximately 79,000 Bpd of firm NGL fractionation capacity;

 

   

Approximately 3.5 Bcf of firm natural gas storage capacity;

 

   

Approximately 0.75 Bcf of interruptible natural gas storage capacity;

 

   

Up to approximately 30,000 Bpd in 2014 to 120,000 Bpd in 2022 of firm NGL transportation capacity on the Texas Express NGL system;

 

   

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

 

   

Approximately 6.0 million barrels of liquids, or MMBbls, of firm NGL storage capacity.

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

Supply and Demand.    Supply for our trucking and marketing business depends to a large extent on the natural gas reserves and rate of drilling within the areas served by our gathering, processing and transportation business. Demand is typically driven by weather-related factors with respect to power plant and utility customers and industrial demand.

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

One of the key components of our trucking and marketing business is our natural gas and NGL purchase and resale business. Through our natural gas and NGL purchase and resale operations, we can efficiently manage the transportation and delivery of natural gas and NGLs from our gathering, processing and transportation systems

 

19


Table of Contents

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

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

Competition.    Our trucking and marketing operations have numerous competitors, including large natural gas and NGL marketing companies, marketing affiliates of pipelines, major oil, natural gas and NGL producers, other trucking, railcar and pipeline operations, independent aggregators and regional marketing companies.

Seasonality

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

REGULATION

Regulation by the FERC of Interstate Common Carrier Liquids Pipelines

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

The ICA gives the FERC the authority to regulate the rates we can charge for service on interstate common carrier pipelines. The ICA requires, among other things, that such rates be “just and reasonable” and that they not be unduly discriminatory or unduly preferential to certain shippers. The ICA permits interested parties to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate the rates to determine if they are just and reasonable. If the FERC finds the new or changed rate unlawful, it is authorized to require the carrier to refund, with interest, the amount of any revenues in excess of the amount that would have been collected during the term of the

 

20


Table of Contents

investigation at the rate properly determined to be lawful. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

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

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

The EP Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561 which adopted an indexing rate methodology for petroleum pipelines. Under these regulations, which became effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made within the ceiling levels may be protested, but such protests generally must show that the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling, although a pipeline is not required to reduce its rate below the level grandfathered under the EP Act. Under Order No. 561, a pipeline must as a general rule utilize the indexing methodology to change its rates. The FERC, however, uses cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances.

The tariff rates for our Ozark system are primarily set under the FERC indexing rules. The tariff rates for our Lakehead and North Dakota systems are set using a combination of the FERC indexing rules (which apply to the base rates on those systems) and FERC-approved surcharges for particular projects that were approved under the FERC’s settlement rules.

Under Order No. 561, the original inflation index adopted by the FERC (for the period January 1995 through June 2001) was equal to the annual change in the Producer Price Index for Finished Goods, or PPI-FG, minus one percentage point. The index is subject to review every five years. For the period from July 2001 through June 2006, the FERC set the index at the PPI-FG without an upward or downward adjustment. For the period from July 2006 through June 2011, the FERC set the index at the PPI-FG plus 1.3 percentage points. The index as of July 1, 2010 was negative, resulting in a general downward adjustment of petroleum pipeline rates as of that date.

On December 16, 2010, the FERC set the index for the period from July 2011 through June 2016 at PPI-FG plus 2.65 percentage points. The FERC’s December 16, 2010 order was challenged and an appeal was filed by a shipper with the D.C Circuit Court. However, on December 6, 2011, the shipper filed a motion requesting that the appeal be dismissed. Therefore no further judicial or commission review of the decision occurred.

 

21


Table of Contents

The index as of July 1, 2013 resulted in an increase of approximately 4.6% to the indexed portion of Lakehead, Ozark and North Dakota rates. No protests were filed and the rates, as filed, went into effect July 1, 2013.

The index as of July 1, 2014 resulted in an increase of approximately 3.9% to the indexed portion of Ozark, North Dakota and Bakken rates. No protests were filed and the rates, as filed, are in effect. Lakehead’s index rate filing was delayed by one month to August 1, 2014 as a result of negotiations with shippers on a component of Lakehead’s settlement rates. No protests were filed and the rates, as filed, are in effect.

FERC Allowance for Income Taxes in Interstate Common Carrier Pipeline Rates

In May 2005, the FERC adopted a policy statement providing that pipelines regulated by FERC that are owned by entities organized as Master Limited Partnerships, or MLPs, could include an income tax allowance in their cost-of-service rates to the extent the income generated from regulated activities was subject to an actual or potential income tax liability. Pursuant to this policy statement, a FERC-regulated pipeline that is a tax pass-through entity seeking such an income tax allowance must establish that its owners, partners or members have an actual or potential income tax obligation on the company’s income from regulated activities. This tax allowance policy was upheld on appeal by the U. S. Court of Appeals for the D.C. Circuit, also referred to as the D.C. Circuit Court, in May 2007. Whether a particular pipeline’s owners have an actual or potential income tax liability is reviewed by the FERC on a case-by-case basis. To the extent any of our FERC-regulated oil pipeline systems were to file cost-of-service rates, their entitlement to an income tax allowance would be assessed under the FERC policy statement and the facts existing at the relevant time.

FERC Return on Equity Policy for Oil Pipelines

On April 17, 2008, the FERC issued a Policy Statement regarding the inclusion of MLPs in the proxy groups used to determine the return on equity, or ROE, for oil pipelines. Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity, 123 FERC ¶ 61,048 (2008), rehearing denied, 123 FERC ¶ 61,259 (2008). No petitions for review of the Policy Statement were filed with the D.C. Circuit Court. The Policy Statement largely upheld the prior method by which ROEs were calculated for oil pipelines, explaining that MLPs should continue to be included in the ROE proxy group for oil pipelines, and that there should be no ceiling on the level of distributions included in the FERC’s current discounted cash flow, or DCF, methodology. The Policy Statement further indicated that the Institutional Brokers’ Estimate System, or IBES, forecasts should remain the basis for the short-term growth forecast used in the DCF calculation and there should be no modification to the current respective two-thirds and one-third weightings of the short and long-term growth factors. The primary change to the prior ROE methodology was the Policy Statement’s holding that the Gross Domestic Product, or GDP, forecast used for the long-term growth rate should be reduced by 50% for all MLPs included in the proxy group. Everything else being equal, that change will result in somewhat lower ROEs for oil pipelines than would have been calculated under the prior ROE methodology. The actual ROEs to be calculated under the new Policy Statement, however, are dependent on the companies included in the proxy group and the specific conditions existing at the time the ROE is calculated in each case.

Accounting for Pipeline Assessment Costs

In June 2005, the FERC issued an order in Docket No. AI05-1 describing how FERC-regulated companies should account for costs associated with implementing the pipeline integrity management requirements of the United States Department of Transportation, or DOT, and the Pipeline and Hazardous Materials Safety Administration, or PHMSA. The order took effect on January 1, 2006. Under the order, FERC-regulated companies are generally required to recognize costs incurred for performing pipeline assessments that are part of a pipeline integrity management program as a maintenance expense in the period in which the costs are incurred. Costs for items such as rehabilitation projects designed to extend the useful life of the system can continue to be

 

22


Table of Contents

capitalized to the extent permitted under the existing rules. The FERC denied rehearing of its accounting guidance order on September 19, 2005.

Prior to 2006, we capitalized first time in-line inspection programs, based on previous rulings by the FERC. In January 2006, we began expensing all first-time internal inspection costs for all our pipeline systems, whether or not they are subject to the FERC’s regulation, on a prospective basis. We continue to expense secondary internal inspection tests consistent with the previous practice. Refer to Note 2. Summary of Significant Accounting Policies included in our consolidated financial statements of this annual report on Form 10-K for additional discussion.

Regulation of Intrastate Natural Gas Pipelines

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

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 rates for the transportation and transmission and sale 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/transmission companies and employees or patrons will be mediated by the OCC. A corporation that fails to comply with OCC rate requirements is subject to contempt proceedings instituted by any affected party.

Regulation by the FERC of Intrastate Natural Gas Pipelines

Our Texas and Oklahoma intrastate pipelines are generally not subject to regulation by the FERC. However, to the extent our intrastate pipelines transport natural gas in interstate commerce, the rates, terms and conditions of such transportation are subject to FERC jurisdiction under Section 311 of the Natural Gas Policy Act of 1978, or NGPA. At least one of our intrastate pipelines will file for FERC approval of new rates in 2015. In addition, under FERC regulations we are subject to market manipulation and transparency rules. This includes the annual reporting requirements pursuant to FERC Order No. 735 et al. Failure to comply with FERC’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 the traditional tests the FERC has used to establish a facility’s status as a gatherer not subject to FERC jurisdiction. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to FERC Order 704 and subsequent reissuances of the Order (currently Order 704-C).

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, historically rates have not fallen

 

23


Table of Contents

under the purview of state regulations for gathering facilities. 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.

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

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

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

Other Regulation

The governments of the United States and Canada have, by treaty, agreed to ensure nondiscriminatory treatment for the passage of oil and natural gas through the pipelines of one country across the territory of the other. Individual international border crossing points require United States government permits that may be terminated or amended at the discretion of the United States Government. These permits provide that pipelines may be inspected by or subject to orders issued by federal or state government agencies.

Tariffs and Transportation Rate Cases

Lakehead system

Under the published rate tariff as of December 31, 2014 for transportation on the Lakehead system, the rates for transportation of light, medium and heavy crude oil from the Canada-United States international border near Neche, North Dakota and from Clearbrook, Minnesota to principal delivery points are set forth below:

 

     Published Transportation Rate Per Barrel(1)  
     Light      Medium      Heavy  

From the international border near Neche, North Dakota:

        

To Clearbrook, Minnesota

   $         0.4457      $         0.4722      $         0.5191  

To Superior, Wisconsin

   $ 0.9382      $ 1.0023      $ 1.1144  

To Chicago, Illinois area

   $ 2.0641      $ 2.2202      $ 2.4939  

To Marysville, Michigan area

   $ 2.4870      $ 2.6768      $ 3.0099  

To Buffalo, New York area

   $ 2.5484      $ 2.7434      $ 3.0845  

Clearbrook, Minnesota to Chicago

   $ 1.8255      $ 1.9549      $ 2.1818  

 

(1)

Pursuant to FERC Tariff No. 43.14.0 as filed with the FERC and with an effective date of August 1, 2014 (converted from $/cubic meters of liquid, or m3, to $/Barrel of liquids, or Bbl).

 

24


Table of Contents

The transportation rates as of December 31, 2014 for medium and heavy crude oil are higher than the transportation rates for light crude oil set forth in this table to compensate for differences in the costs of shipping different types and grades of liquid hydrocarbons. The Lakehead system periodically adjusts transportation rates as allowed under the FERC’s index methodology and the tariff agreements described below.

Base Rates

The base portion of the transportation rates for our Lakehead system are subject to an annual adjustment, which cannot exceed established ceiling rates as approved by the FERC and are determined in compliance with the FERC approved index methodology.

Facilities Surcharge Mechanism

In June 2004, the FERC approved an Offer of Settlement in Docket No. OR04-2-000 between Lakehead and CAPP, which implemented a Facilities Surcharge Mechanism, or FSM, to be calculated separately from and incrementally to the then-existing surcharges in its tariff rates, Enbridge Energy, Limited Partnership, 107 FERC ¶ 61,336 (2004). The FSM includes additional projects negotiated and agreed upon between Lakehead and CAPP as a transparent, cost-of-service based tariff mechanism. This allows the Lakehead system to recover the costs associated with particular shipper-requested projects through an incremental surcharge layered on top of the existing base rates. The FSM Settlement requires the Lakehead system to adjust the FSM annually to reflect the latest estimates for the upcoming year and to adjust for the difference between estimates and actual cost and throughput data from the prior year.

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

 

  (1) The Griffith Hartsdale Transfer Lines Project;

 

  (2) The Hartsdale Tanks Project;

 

  (3) The Superior Manifold Modification Project; and

 

  (4) The Line 17 (Toledo) Expansion Project.

On August 14, 2008, the FERC approved an Amendment to the FSM Settlement to allow the Lakehead system to include in the FSM particular shipper-requested projects that are not yet in service as of April 1st of each year, provided there is an annual adjustment for differences between actual and estimated throughput and costs. Enbridge Energy, Limited Partnership, 124 FERC ¶ 61,159 (2008). The FERC also approved the addition of four new projects to the FSM in Docket No. OR08-10-000:

 

  (5) Southern Access Mainline Expansion;

 

  (6) Tank 34 at Superior Terminal and Tank 79 at Griffith Terminal;

 

  (7) Clearbrook Manifold; and

 

  (8) Tank 35 at Superior Terminal and Tank 80 at Griffith Terminal.

 

25


Table of Contents

On August 28, 2009, the FERC accepted the Supplement to the Settlement in Docket No. OR09-5-000 to allow the following three new projects:

 

  (9) Southern Lights Replacement Capacity Project;

 

  (10) Eastern Access (Trailbreaker) Backstopping Agreement; and

 

  (11) Line 5 Expansion Backstopping Agreement.

On March 30, 2010, the FERC accepted the Supplement to the Settlement in Docket No. OR10-7-000 to permit the recovery of the costs associated with two new projects:

 

  (12) Alberta Clipper Pipeline; and

 

  (13) Line 3 Conversion Project.

On March 31, 2011, the FERC accepted the Supplement to the Settlement in Docket No. OR11-5-000 to permit the recovery of the costs associated with one new project:

 

  (14) Line 6B Integrity Program.

On March 29, 2012, the FERC accepted the Supplement to the Settlement in Docket No. OR12-8-000 to permit the recovery of the costs associated with two new projects:

 

  (15) Line 6B Pipeline Replacement and Dig Program Project; and

 

  (16) Griffith Terminal Expansion Project.

On February 13, 2013, the FERC accepted the Supplement to the Settlement in Docket No. OR13-11-000 to permit the recovery of the costs associated with two more projects:

 

  (17) Flanagan Tank Replacement Project; and

 

  (18) Eastern Access Phase 1 Mainline Expansion Project.

On January 31, 2014, the FERC accepted the Supplement to the Settlement in Docket No. OR14-13-000 to permit the recovery of the costs associated with two more projects:

 

  (19) Eastern Access Phase 2 Mainline Expansion Project; and

 

  (20) 2014 Mainline Expansions Project.

On July 31, 2014, the FERC accepted the Supplement to the Settlement in Docket No. OR14-33-000 to permit the recovery of the costs associated with three more projects:

 

  (21) Line 14;

 

  (22) Agreed-upon Legacy Integrity; and

 

  (23) Agreed-upon Future Integrity.

The Line 14 project, or Project 21 above, permits the recovery of certain costs related to Line 14 of the Lakehead system. The Agree-upon Legacy Integrity project, or Project 22 above, permits the recovery of the

 

26


Table of Contents

remaining cost-of-service related to certain previously agreed-upon integrity related projects. The Agreed-upon Future Integrity project, or Project 23 above, permits the recovery of 50% of the costs of certain agreed-upon integrity related projects to be conducted on the Lakehead system.

On December 1, 2014, Enbridge filed a Supplement to the Settlement in Docket No. OR15-4 seeking approval for the recovery of the costs associated with two more projects:

 

  (24) 2015-16 Mainline and Eastern Access Expansions.

The 2015-16 Mainline and Eastern Access Expansions projects have an overall estimated capital cost of $1.8 billion and include four main components:

 

  a) Expansion of Alberta Clipper, or Line 67, from 570,000 Bpd to 800,000 Bpd. It includes four new pump stations and modifications at three existing pump stations. The total estimated cost is $240 million;

 

  b) Expansion of Southern Access, or Line 61, from 560,000 Bpd to 800,000 Bpd. It includes new pump stations; modifications at four existing pump stations; and tanks at Flanagan, Illinois, and Superior, Wisconsin. The total estimated cost is $755 million;

 

  c) Expansion of Line 6B from 500,000 Bpd to 570,000 Bpd. It includes modifications at existing pump stations and terminal upgrades. The total estimated cost is $310 million; and

 

  d) Construction of Line 78, a twin of our existing Line 62, with an initial capacity of 570,000 Bpd. The new 36-inch pipeline from Flanagan, Illinois to Hartsdale, Indiana includes a new initiating pump station. The total estimated cost is $495 million and, subject to regulatory and other approvals.

On December 19, 2014, Flint Hills Resources, L.P. filed a Motion to Intervene and Request for Clarification or, In the Alternative Protest, and on December 29, 2014, Suncor Energy Marketing Inc. filed a Motion to Intervene and Protest the Supplement filing. Suncor requested that the FERC defer action on the Supplement until after Lakehead has filed a tariff incorporating the new project and that the tariff be allowed to go into effect subject to refund.

As of December 31, 2014, the FSM was $1.1377 per barrel for light crude oil movements from the Canada-United States international border near Neche, North Dakota to Chicago, Illinois.

Other Tariff and Transportation Rate Cases

Lakehead was subject to one complaint during 2014 that was initiated in 2012 and dismissed by the FERC on October 1, 2014. High Prairie Pipelines LLC, a subsidiary of Saddle Butte Pipeline, LLC, or High Prairie, filed a complaint with the FERC on May 17, 2012, claiming that Enbridge unduly discriminated against High Prairie by failing to provide High Prairie a connection at the Enbridge Clearbrook Terminal. Enbridge formally denied the accusation in a motion to dismiss on June 6, 2012, submitting that FERC does not have the authority to force a pipeline connection. On March 22, 2013, the FERC issued an order dismissing the complaint. On April 22, 2013, High Prairie filed a Request for Rehearing, which the FERC accepted on May 20, 2013. On October 1, 2014, the FERC issued an Order Denying Rehearing.

International Joint Tariff

FERC Tariff No. 45.3.0, issued May 30, 2014, revised the International Joint Tariff, or IJT, effective July 1, 2014, by increasing the transportation tolls by 0.89%. The IJT provides rates applicable to the transportation of

 

27


Table of Contents

petroleum from all receipt points in western Canada on the Enbridge Pipelines Inc., or Enbridge Pipelines, Canadian Mainline system to all delivery points on the Lakehead Pipeline system owned by Enbridge Energy and to delivery points on the Canadian Mainline located downstream of the Lakehead system. In summary, the IJT provides a simplified tolling structure to cover transportation services that cross the international border and provides a rate that is equal to or less than the sum of the combined Canadian Mainline and Lakehead system rates on file and in effect.

Mid-Continent system

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

On May 30, 2014, our Ozark system filed FERC Tariff 48.4.0 with effective dates of July 1, 2014. The tariff increased Ozark system rates in compliance with the indexed rate ceilings allowed by the FERC, and incorporates the multiplier of 1.038858 that was issued by the FERC in Docket No. RM93-11-000 on May 14, 2014.

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

 

     Published
Transportation
Rate Per Barrel(1)(2)
 

From Cushing, Oklahoma to Wood River, Illinois

   $ 0.6463  

 

(1) 

Pursuant to FERC Tariff No. 48.4.0 as filed with the FERC on May 30, 2014, with an effective date of July 1, 2014.

 

(2) 

The transportation rates apply to light crude oil only. Medium and heavy crude oil transportation rates on the system are higher.

North Dakota system

The North Dakota system consists of both gathering and trunkline assets. Effective January 1, 2008, two new surcharges were implemented as a part of the North Dakota Phase 5 expansion program, referred to as North Dakota Phase 5. In August 2006, the North Dakota system submitted the Phase 5 Offer of Settlement to the FERC for an expansion of the system, which was approved by the Commission on October 31, 2006 in Docket No. OR06-9-000. The Phase 5 Offer of Settlement outlined the mainline expansion and looping surcharges as cost-of-service based surcharges that are adjusted each year for differences between estimated and actual costs and volumes and are not subject to the FERC indexing methodology. These surcharges were initially applicable for five years immediately following the in-service date of North Dakota Phase 5, which was January 2008. The mainline expansion surcharge is applied to all routes with a destination of Clearbrook and the looping surcharge is applied to volumes originating at either Trenton or Alexander, North Dakota. Effective April 1, 2010, we extended the term of the looping surcharge on our North Dakota system by four years, ending on December 31, 2016 rather than the original date of December 31, 2012. The impact of the term extension reduced the looping surcharge substantially thereby moderating the rate impact on shippers. The mainline expansion surcharge expired on December 31, 2012.

On January 18, 2008, Enbridge North Dakota submitted an Offer of Settlement to the FERC to facilitate the Phase 6 expansion of the North Dakota system. Under the terms of the settlement, which were approved by the FERC on October 20, 2008 in Docket No. OR08-6-000, expansion costs are recovered through a cost-of-service based surcharge on all shipments to Clearbrook, Minnesota. The surcharge is in effect for seven years and is adjusted on an annual basis to actual costs and volumes. It is not subject to the FERC index methodology. The Phase 6 surcharge became effective on January 1, 2010 and is in addition to existing base rates and the Phase 5 surcharges.

 

28


Table of Contents

On March 1, 2013, FERC Tariff 72.22.0 was filed, adjusting the Phase 5 looping and Phase 6 surcharges and cancelling the Phase 5 mainline surcharge, which expired on December 31, 2012. The filing was protested by one shipper who wanted the surcharge to be applicable to barrels delivered to Berthold, North Dakota in addition to Clearbrook, Minnesota. The FERC rejected the protest on the basis that Enbridge correctly implemented the terms of the approved Offer of Settlement covering the surcharge. A complaint was filed by the same shipper on July 25, 2013 in Docket No. OR13-28-000, asking the FERC to dismiss the Offer of Settlement on the basis that it no longer reflected the circumstances on the North Dakota system. The FERC rejected the complaint in Order 145 FERC ¶ 61,050 on the basis that the complainant did not provide sufficient evidence to convince the FERC to overturn an approved Settlement. On December 13, 2013, the shipper filed a Petition for Review with the U.S. District Court of Appeals. Oral arguments before the court were held on November 14, 2014, and a ruling is expected in mid-2015.

On August 26, 2010, the North Dakota system and Enbridge Pipelines (Bakken) L.P. filed a Petition for Declaratory Order seeking the approval of priority service for the North Dakota portion of the Bakken Project as well as the overall tariff and rate structure for the United States portions of the program. The Petition for Declaratory Order was approved by the FERC on November 22, 2010 in Docket No. OR10-19-000. On March 1, 2013, the Bakken Project went into service and has the capability to transport 145,000 Bpd of Bakken crude from the North Dakota system to Cromer, Manitoba, Canada.

On November 2, 2012, the North Dakota system submitted a Petition for Declaratory Order seeking approval of a related Offer of Settlement with respect to a major expansion and extension of the North Dakota system known as the Sandpiper Project. The project would result in a substantial increase in the capacity available to transport Bakken crude both to and through Clearbrook, North Dakota to Superior, Wisconsin. The terms of the proposal include, among other things, the addition of a cost-of-service rate surcharge to the existing rates to Clearbrook, and a new cost-of-service tariff rate from Clearbrook to Superior. On March 22, 2013, the Petition was denied by the FERC on the basis that an Offer of Settlement requires the unanimous approval of all shippers. A revised proposal for the Sandpiper Project, including the availability of contracted space on the pipeline, is currently being offered to shippers through a successful open season and on February 19, 2014, a revised Petition for Declaratory Order was filed with the FERC. In this petition, the North Dakota system proposed a tariff structure that involves separate rates for committed priority volumes, committed non-priority volumes, and uncommitted volumes. On May 15, 2014, the Petition for Declaratory Order was approved by the FERC in Docket No. OR14-21-000. The Sandpiper project is expected to be placed into service during 2017, subject to obtaining regulatory and other approvals.

Effective February 1, 2014, FERC Tariff 3.1.0 was filed to establish initial gathering charges at Alexander, North Dakota. The $0.01046/bbl interconnection rate resulted from a shipper’s request for a pipeline interconnection at that location.

Effective April 1, 2014, FERC Tariff 3.3.0 was filed to update the calculation of surcharges for two previously approved expansions, the Phase 5 Looping and Phase 6 Mainline. As previously mentioned, these surcharges are cost-of-service based surcharges that are adjusted each year to actual costs and volumes and are not subject to the FERC indexing methodology. This filing increased the Phase 5 Looping surcharge from $0.20 to $0.23 and the Phase 6 Mainline surcharge from $0.83 to $0.87.

Effective May 8, 2014, FERC Tariff 3.4.0 was filed to cancel transportation rates on the North Dakota system from Flat Lake, Montana, as the pipeline is no longer providing service from that receipt point.

Effective July 1, 2014, FERC Tariff 3.5.0 was filed to increase North Dakota system rates in compliance with the indexed rate ceilings allowed by the FERC. This filing incorporated the multiplier of 1.038858, which was issued by the FERC in Docket No. RM93-11-000 on May 14, 2014.

 

29


Table of Contents

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

 

      Published
Transportation
Rate Per
Barrel(1)
 

From Glenburn, Minot, Newburg, Sherwood, Berthold and Stanley, North Dakota to Clearbrook, Minnesota

   $ 1.9538   

From Grenora, North Dakota to Clearbrook, Minnesota

   $ 2.1116   

From Reserve, Montana to Clearbrook, Minnesota

   $ 2.1465   

From Tioga, North Dakota to Clearbrook, Minnesota

   $ 1.9884   

From Trenton, North Dakota to Clearbrook, Minnesota

   $ 2.5197   

From Alexander, North Dakota to Clearbrook, Minnesota

   $ 2.5719   

From Little Muddy, North Dakota to Clearbrook, Minnesota

   $ 2.5197   

From Grenora, North Dakota to Tioga, North Dakota

   $ 0.7393   

From Reserve, Montana to Tioga, North Dakota

   $ 0.7719   

From Trenton, North Dakota to Tioga, North Dakota

   $ 0.8815   

From Alexander, North Dakota to Tioga, North Dakota

   $ 0.9336   

From Little Muddy, North Dakota to Tioga, North Dakota

   $ 0.8815   

From (pump-over) Stanley, North Dakota to Stanley, North Dakota

   $ 0.2717   

From Tioga, North Dakota to Stanley, North Dakota

   $ 0.9909   

From Grenora, North Dakota to Stanley, North Dakota

   $ 1.1360   

From Reserve, Montana to Stanley, North Dakota

   $ 1.1682   

From Trenton, North Dakota to Stanley, North Dakota

   $ 1.5300   

From Alexander, North Dakota to Stanley, North Dakota

   $ 1.5782   

From Little Muddy, North Dakota to Stanley, North Dakota

   $ 1.5300   

From Berthold, North Dakota to Berthold, North Dakota

   $ 0.7898   

From Stanley, North Dakota to Berthold, North Dakota

   $ 0.9075   

From Tioga, North Dakota to Berthold, North Dakota

   $ 0.9909   

Gathering from Newburg, North Dakota

   $ 0.8946   

 

(1)

Pursuant to FERC Tariff No. 3.5.0 as filed with the FERC on May 30, 2014, with an effective date of July 1, 2014.

Bakken System

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

On March 1, 2013, the Bakken pipeline went into service and it currently has the capability to transport 145,000 Bpd from the North Dakota system to Cromer, Manitoba, Canada.

Local Tariff

Effective July 1, 2014, the North Dakota system filed on behalf of the Bakken system with FERC tariff 2.1.0. The tariff increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporated the multiplier of 1.038858 issued by the FERC on May 14, 2014 in Docket No. RM93-11-000. This filing also included an adjustment for the operating costs charge, which is part of the committed rate structure. The committed rate structure consists of two components—a base committed rate and an operating costs charge. The operating costs charge is a flow-through of the related operating costs, and is based on throughput. The initial operating costs charge at the in-service date for Bakken on March 1, 2013, was $0.33. With the aforementioned filing, the operating costs charge decreased to $0.22.

 

30


Table of Contents

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

 

      Published
Transportation
Rate Per Barrel(1)
 

From Berthold, North Dakota to the international border near Portal, North Dakota

   $ 1.2421  

 

(1) 

Pursuant to FERC Tariff No. 2.1.0 as filed with the FERC on May 30, 2014, with an effective date of July 1, 2014.

International Joint Tariff

Effective July 1, 2014, the Bakken system filed FERC tariff 3.1.0. This filing was a compliance filing in accordance with transportation service agreements included in the Petition for Declaratory Order filed on August 26, 2010 in Docket No. OR10-10-000.

Safety Regulation and Environmental

General

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

Pipeline Safety and Transportation Regulation

Our transmission and gathering pipelines are subject to regulation by the DOT and PHMSA, under the Pipeline Safety Act of 1992, or PSA, relating to the design, installation, testing, construction, operation, replacement and management of transmission and gathering pipeline facilities. PHMSA is the agency charged with regulating the safe transportation of hazardous materials under all modes of transportation, including interstate and intrastate pipelines. Periodically the PSA has been reauthorized and amended, imposing new mandates on the regulator to promulgate new regulations and imposing direct mandates on operators of pipelines.

On December 29, 2006, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, or PIPES of 2006, was enacted, which further amended the PSA. Many of the provisions were welcomed, including strengthening excavation damage prevention and enforcement. The most significant provisions of PIPES of 2006 that affect us include a mandate to PHMSA to remove most exemptions from federal regulations for liquid pipelines operating at low stress and mandates PHMSA to undertake rulemaking requiring pipeline operators to have a human factors management plan for pipeline control room personnel, including consideration for controlling hours of service. On December 3, 2009, the final rule for the Control Room Management/Human Factors was published and in June 2011, the rule’s implemental deadlines were expedited in order to realize the safety benefits sooner than established in the original rule. The final rule applying safety regulations to all rural onshore hazardous liquid low-stress pipelines was published May 5, 2011 and became effective October 1, 2011.

In April 2011, as a reaction to recent significant accidents involving natural gas explosions and hazardous liquids releases, the DOT Secretary Ray LaHood and PHMSA issued a Call to Action to engage all the state pipeline regulatory agencies, technical and subject matter experts, and pipeline operators to accelerate the repair, rehabilitation, and replacement of the highest-risk pipeline infrastructure. The Call addresses many concerns related to pipeline safety, such as ensuring pipeline operators know the age and condition of their pipelines, proposing new regulations to strengthen reporting and inspection requirements, and making information about pipelines and the safety record of pipeline operators easily accessible to the public.

 

31


Table of Contents

In order to further strengthen pipeline safety regulations, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law on January 3, 2012. As a result of this Act, PHMSA will be finalizing new rules to implement lessons learned from recent pipeline accidents. Pending legislation includes: requiring automatic or remote-controlled shutoff valves on new or replaced transmission pipeline facilities and requiring operators to use leak detection systems where practicable. In addition, to support PHMSA’s investigation and enforcement operations for the increasing number of regulations, the Act authorizes additional PHMSA inspectors, and doubles the maximum civil penalties for pipeline operators who fail to observe safety rules. Also included within this act are: the consideration of expanding integrity management requirements beyond high consequence areas, the assessment of the need for new regulations covering diluted bitumen transportation, the requirement to validate and verify maximum allowable operating pressures, and the determination of the effect of depth of cover over buried pipelines in accidental releases of hazardous liquids at water crossings.

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

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

Environmental Regulation

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

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

 

32


Table of Contents

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 of 1970, as amended, 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 are currently in full compliance. Facilities subject to existing Greenhouse Gas Reporting rules reported emissions prior to the March 31, 2012 deadline for 2011 emissions. Our facilities subject to existing EPA Greenhouse Gas Reporting rules have reported emissions prior to the annual filing deadlines. The EPA has recently signed proposed rules that would subject gathering and booster stations to the Greenhouse Gas Reporting Rule, Subpart W regulations. Although these proposed regulations would increase the recordkeeping and reporting requirements, the increased burden would not be different than that imposed on our competitors. On November 10, 2014, the EPA rescinded a Federal Implementation Plan, or FIP, for Texas for Greenhouse Gas Prevention of Significant Deterioration, or GHG PSD, permitting. The Texas State Implementation Plan, or SIP, now has the authority to regulate Greenhouse Gas emissions and approve GHG PSD permits in Texas. This new approval authority should simplify the GHG PSD permitting process in Texas.

On August 23, 2011, the EPA proposed New Source Performance Standards, or NSPS, Subpart OOOO for volatile organic compounds, or VOCs, and sulfur dioxide, or SO2, emissions from the Oil and Natural Gas Sector. The final standards were published and became effective on August 16, 2012. The compliance dates range from October 15, 2012, to October 15, 2013, dependent on the affected equipment. The EPA amended the rule to extend compliance dates for certain storage vessels on August 2, 2013, and may issue additional revised rules in the future. There will be additional costs across the industry to attain compliance with the NSPS, Subpart OOOO, but we do not expect a material effect on our financial statements. 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. The EPA last updated these standards in 2008, then setting the standard at 75 Ppb. If this new, more stringent standard is finalized, numerous counties will fall into the non-attainment category, resulting in more costly pollution control requirements.

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

 

33


Table of Contents

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

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

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

EMPLOYEES

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

INSURANCE

Our operations are subject to many hazards inherent in the liquid petroleum and natural gas gathering, treating, processing and transportation industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We maintain commercial liability insurance coverage that is consistent with coverage considered customary for our industry. We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries through the policy renewal date of May 1, 2015. The insurance coverage also includes property insurance coverage on our assets that includes earnings interruption resulting from an insurable event, except for

 

34


Table of Contents

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 the Partnership has entered into with Enbridge and other Enbridge subsidiaries.

The coverage limits and deductible amounts at December 31, 2014 for our insurance policies:

 

Insurance Type                                                 

   Coverage Limits      Deductible
Amount
 
     (in millions)  

Property and business interruption

   Up to $ 860.0       $ 10.0  

General liability

   Up to $ 700.0       $ 0.1  

Pollution liability (as included under General Liability)

   Up to $ 700.0       $ 30.0  

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

TAXATION

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

AVAILABLE INFORMATION

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

Item 1A.    Risk Factors

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

RISKS RELATED TO OUR BUSINESS

Our actual construction and development costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate, which may limit our ability to maintain or increase cash distributions.

Our strategy contemplates significant expenditures for the development, construction or other acquisition of energy infrastructure assets. The construction of new assets involves numerous regulatory, environmental, legal, political, permitting at federal, state and local levels, materials and labor cost and operational risks that are

 

35


Table of Contents

difficult to predict and beyond our control. As a result, we may not be able to complete our projects at the costs currently estimated or within the time periods we have projected. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:

 

   

using cash from operations;

 

   

delaying other planned projects;

 

   

incurring additional indebtedness; or

 

   

issuing additional equity.

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

Our revenues and cash flows may not increase immediately on our expenditure of funds on a particular project. For example, if we build a new pipeline or expand an existing facility, the design, construction, development and installation may occur over an extended period of time and we may not receive any material increase in revenue or cash flow from that project until after it is placed in service and customers begin using the systems. 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 ability to access capital markets and credit on attractive terms to obtain funding for our capital projects and acquisitions may be limited.

Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Domestic and international economic conditions affect the functioning of capital markets and the availability of credit. Adverse economic conditions, such as those prevalent during the recessionary period of 2008 and through much of 2010, periodically result in weakness and volatility in the capital markets, which in turn can limit, temporarily or for extended periods, our ability to raise capital through equity or debt offerings. Additionally, the availability and cost of obtaining credit commitments from lenders can change as economic conditions and banking regulations reduce the credit that lenders have available or are willing to lend. These conditions, along with significant write-offs in the financial services sector and the re-pricing of market risks, can make it difficult to obtain funding for our capital needs from the capital markets on acceptable economic terms. As a result, we may revise the timing and scope of these projects as necessary to adapt to prevailing market and economic conditions.

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

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

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

 

36


Table of Contents

Currently, we are parties to certain International Swaps and Derivatives Association, Inc., or ISDA®, agreements associated with the derivative financial instruments we use to manage our exposure to fluctuations in commodity prices. These ISDA® agreements require us to provide assurances of performance if our counterparties’ exposure to us exceeds certain levels or thresholds. We generally provide letters of credit to satisfy such requirements. At December 31, 2014, we have provided $329.6 million in the form of letters of credit as assurances of performance for our then outstanding derivative financial instruments. In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by S&P and Moody’s, we would be required to provide letters of credit in substantially greater amounts to satisfy the requirements of our ISDA® agreements. For example if our credit ratings had been at the lowest level of investment grade at December 31, 2014, we would have been required to provide additional letters of credit in the aggregate amount of $50.6 million. The amounts of any letters of credit we would have to establish under the terms of our ISDA® agreements would reduce the amount that we are able to borrow under our senior unsecured revolving credit facility and our 364-day credit facility, referred to as our Credit Facilities.

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

We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions at the current level. The amount of cash we are able to distribute depends on the amount of cash we generate from our operations, which can fluctuate quarterly based upon a number of factors, including:

 

   

the operating performances of our assets;

 

   

commodity prices;

 

   

actions of government regulatory bodies;

 

   

the level of capital expenditures we make;

 

   

the amount of cash reserves established by Enbridge Management;

 

   

our ability to access capital markets and borrow money;

 

   

our debt service requirements and restrictions in our credit agreements;

 

   

the ability of MEP to make distributions to us;

 

   

fluctuations in our working capital needs; and

 

   

the cost of acquisitions.

In addition, the amount of cash we distribute depends primarily on our cash flow rather than net income or net loss. Therefore, we may make cash distributions for periods in which we record net losses or may make no distributions for periods in which we record net income.

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

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

 

   

the risk of incorrect assumptions regarding the future results of the acquired operations or expected cost reductions or other synergies expected to be realized as a result of acquiring such operations;

 

37


Table of Contents
   

a decrease in liquidity as a result of utilizing significant amounts of available cash or borrowing capacity to finance an acquisition;

 

   

the loss of critical customers or employees at the acquired business;

 

   

the assumption of unknown liabilities for which we are not fully and adequately indemnified;

 

   

the risk of failing to effectively integrate the operations or management of acquired assets or businesses or a significant delay in such integration; and

 

   

diversion of management’s attention from existing operations.

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

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

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

 

   

competition;

 

   

regulatory action;

 

   

weather conditions;

 

   

storage levels;

 

   

alternative energy sources;

 

   

decreased demand;

 

   

fluctuations in energy commodity prices;

 

   

environmental or other governmental regulations;

 

   

economic conditions;

 

   

supply disruptions;

 

   

availability of supply connected to our pipeline systems; and

 

   

availability and adequacy of infrastructure to move, treat and process supply into and out of our systems.

As an example, the volume of shipments on our Lakehead system depends heavily on the supplies of western Canadian crude oil. Insufficient supplies of western Canadian crude oil will adversely affect our business by limiting shipments on our Lakehead system. Decreases in conventional crude oil exploration and production activities in western Canada and other factors, including supply disruption, higher development costs and competition, can slow the rate of growth of our Lakehead system. The volume of crude oil that we transport on our Lakehead system also depends on the demand for crude oil in the Great Lakes and Midwest regions of the

 

38


Table of Contents

United States and the volumes of crude oil and refined products delivered by others into these regions and the province of Ontario. Pipeline capacity for the delivery of crude oil to the Great Lakes and Midwest regions of the United States currently exceeds refining capacity.

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

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

Our financial performance may be adversely affected by risks associated with the Alberta Oil Sands.

Our Lakehead system is highly dependent on sustained production from the Alberta Oil Sands. Growth in production from the oil sands over the past decade has remained strong due to high oil prices and improved production methods; however the industry faces a number of risks associated with the scope and scale of its projects. Factors and risks affecting the Oil Sands industry include:

 

   

reduced crude oil prices;

 

   

cost inflation;

 

   

labor availability;

 

   

environmental impact;

 

   

reputation management;

 

   

changing policy and regulation; and

 

   

commodity price volatility.

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

 

39


Table of Contents

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

Competition may reduce our revenues.

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

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

Our North Dakota system faces increased competition from rail transportation driven by limited transportation infrastructure to key markets. These transportation and market access constraints have resulted in large crude oil price differences between the North Dakota supply basin and refining market centers. If increased transportation infrastructure is delayed or not built, our North Dakota system could continue to experience reduced system utilization.

We also encounter competition in our natural gas gathering, treating, and processing and transmission businesses. A number of new interstate natural gas transmission pipelines being constructed could reduce the revenue we derive from the intrastate transmission of natural gas. Many of the large wholesale customers served by our natural gas systems have multiple pipelines connected or adjacent to their facilities. Thus, many of these wholesale customers have the ability to purchase natural gas directly from a number of pipelines or from third parties that may hold capacity on other pipelines. Most natural gas producers and owners have alternate gathering and processing facilities available to them. In addition, they have other alternatives, such as building their own gathering facilities or, in some cases, selling their natural gas supplies without processing. Some of our natural gas marketing competitors have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.

Our gas marketing operations involve market and regulatory risks.

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

 

   

our ability to negotiate on a timely basis natural gas purchase and sales agreements in changing markets;

 

   

reluctance of wholesale customers to enter into long-term purchase contracts;

 

40


Table of Contents
   

consumers’ willingness to use other fuels when natural gas prices increase significantly;

 

   

timing of imbalance or volume discrepancy corrections and their impact on financial results;

 

   

the ability of our customers to make timely payment;

 

   

inability to match purchase and sale of natural gas on comparable terms; and

 

   

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

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

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

The relatively high costs and large up front capital investments required by oil sands projects involves significant assumptions concerning short-term and long-term crude oil fundamentals including world supply and demand, North American supply and demand, and price outlook among many other factors. As oil sands production is long-term in nature, the long-term outlook is significant to a producer’s investment decision. Short-term decisions may impact the annual rate of future supply growth from the oil sands region.

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

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

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

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

For 2015, we expect approximately 47% of our gross margin within our Natural Gas segment to be attributable to contracts with some degree of commodity price exposure. 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 adversely affect our results of operation and cash flows and ability to make distributions.

 

41


Table of Contents

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

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

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

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

Increased regulation and regulatory scrutiny may reduce our revenues.

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

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

Our pipeline, gathering, processing and trucking operations are subject to federal, state and local laws and regulations relating to environmental protection and operational and worker safety. Numerous governmental authorities have the power to enforce compliance with the laws and regulations they administer and permits they issue, oftentimes imposing complex requirements and necessitating capital expenditures or increased operating costs to achieve compliance. Our failure to comply with these laws, regulations and operating permits can result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Our operation of liquid petroleum and natural gas gathering, processing, treating and transportation facilities exposes us to the risk of incurring significant environmental and safety-related costs and liabilities. Additionally, operational modifications,

 

42


Table of Contents

including pipeline restrictions, necessary to comply with regulatory requirements and resulting from our handling of liquid petroleum and natural gas, historical environmental contamination, accidental releases or upsets, regulatory enforcement, litigation or safety and health incidents can also result in significant cost or limit revenues and volumes. Further, environmental and operational safety laws and regulations, including but not limited to pipeline safety, wastewater discharge and air emission requirements, continue to become more stringent over time, particularly those related to the oil and gas industry. We may incur joint and several strict liability under these environmental laws and regulations in connection with discharges or releases of liquid petroleum and natural gas and wastes on, under or from our properties and facilities, many of which have been used for gathering or processing activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of properties through which our gathering systems pass and facilities where our liquid petroleum and natural gas or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may also incur costs in the future due to changes in environmental and safety laws and regulations, or re-interpretations of enforcement policies or claims for personal, property or environmental damage. We may not be able to recover these costs from insurance or through higher rates.

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

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

The EPA concluded that the April 2010 issuance of regulations to control the greenhouse gas emissions from light duty motor vehicles (the “tailpipe rule”) automatically triggered provisions of the CAA that, in general, potentially could require stationary source facilities that emit more than 250 tons per year of carbon dioxide equivalent to obtain permits to demonstrate that best practices and technology are being used to minimize greenhouse gas emissions. On May 13, 2010, the EPA issued the “tailoring rule,” which served to increase the greenhouse gas emissions threshold that triggers the permitting requirements for major new (and major modifications to existing) stationary sources. This rule was upheld by the U.S. Court of Appeals for the District of Columbia Circuit (Coalition for Responsible Regulation v. EPA) and then subsequently revised by the U.S. Supreme Court in 2013 (Utility Air Regulatory Group v. EPA). Under the phased-in approach now being implemented by the EPA, for most purposes, new permitting provisions to reduce greenhouse gas emissions are required for new major source facilities that also emit 100,000 tons per year or more of carbon dioxide equivalent, or CO2e, and existing major source facilities making major modifications that also would increase greenhouse gas emissions by 75,000 CO2e. The EPA has also indicated in rulemakings that it may further reduce the current regulatory thresholds for greenhouse gas emissions, making additional sources subject to permitting. The EPA has stated, consistent with President Obama’s Climate Action Plan, that it intends to assess methane and other greenhouse gas emissions from the oil and gas sector and adopt amended regulations by the end of 2016 for the sector if further reductions are warranted.

 

43


Table of Contents

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

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

A significant portion of our customers’ natural gas production is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in Congress. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential impacts of hydraulic fracturing on drinking water resources; the multi-year study’s individual research projects began publishing results in 2013, and individual studies are ongoing. In addition, the EPA has announced its intention to regulate wastewater discharges from hydraulic fracturing and other natural gas production activities under the CWA and is scheduled to issue a proposed rule in 2015.

On April 17, 2012, the EPA also approved final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. These new rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through flaring until 2015, after which reduced emission or “green” completions must be used. The rules also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas producing plants, and 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. These rules 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. In addition, at least one municipality in a state in which we operate, the City of Denton, Texas, has followed others in adopting bans or severely restricting hydraulic fracturing activities. Litigation concerning this ban, as well as others, is ongoing. We cannot predict whether any legislation or regulation will be enacted and if so, what its provisions would be. If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines. These factors could

 

44


Table of Contents

reduce the volumes of natural gas and NGLs available to move through our gathering and other systems, which could materially and adversely affect our financial condition, results of operations and cash flows, as well as our ability to make cash distributions to our unitholders.

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

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

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

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 be materially impacted by changes in estimation, commodity prices and other factors.

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

 

   

physical, which results from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;

 

   

degradation resulting from mixing at the interface within our pipeline systems or terminals and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and

 

   

revaluation, which are a function of crude oil prices, the level of our carriers’ inventory and the inventory positions of customers.

 

45


Table of Contents

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

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

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

Terrorist attacks and threats, cyber-attacks, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist or cyber-attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

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

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

The full impact of the Dodd-Frank Act on our hedging activities as an end user is uncertain at this time, as the CFTC has not yet promulgated final regulations implementing some of the key provisions on margining or position limits. We may have 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 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

 

46


Table of Contents

capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our willingness or ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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

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

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

We, as financial support provider, entered into a financial support agreement with Midcoast Operating, pursuant to which we will provide letters of credit and guarantees, not to exceed $700 million in the aggregate at any time outstanding, in support of the financial obligations of Midcoast Operating and its wholly owned subsidiaries under derivative agreements and natural gas and NGL purchase agreements to which Midcoast Operating, or one or more of its wholly owned subsidiaries, is a party. Our rights to payments under the financial support agreement are subordinated to the rights of the lenders under the private placement debt of MEP and the revolving credit facility of MEP and Midcoast Operating during the continuation of a default under their revolving credit facility. If Midcoast Operating experiences financial or other problems and fails to comply with their revolving credit facility, it would limit our ability to receive payment of amounts owed to us under this agreement. In addition, MEP and Midcoast Operating are restricted under their revolving credit facility in certain circumstances involving certain defaults thereunder or any events of defaults thereunder from making distributions to us. Any inability of MEP or Midcoast Operating to make distributions, or of Midcoast Operating to repay its indebtedness to us, could reduce our cash flows and affect our results of operations.

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

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

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

 

47


Table of Contents

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

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

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

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

 

   

permits our General Partner to make a number of decisions, including the determination of which factors it will consider in resolving conflicts of interest, in its “sole discretion.” This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give consideration to any interest of, or factors affecting, us, our affiliates or any unitholder;

 

   

provides that any standard of care and duty imposed on our General Partner will be modified, waived or limited as required to permit our General Partner to act under our partnership agreement and to make any decision pursuant to the authority prescribed in our partnership agreement, so long as such action is reasonably believed by the General Partner to be in our best interests; and

 

   

provides that our General Partner and its directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions if they acted in good faith.

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

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

Conflicts of interest may arise from time to time among Enbridge and its shareholders, on the one hand, and us and our unitholders and Enbridge Management and its shareholders, on the other hand. Conflicts of interest may also arise from time to time between us and our unitholders, on the one hand, and Enbridge Management and its shareholders, on the other hand. In managing and controlling us as the delegate of our General Partner, Enbridge Management may consider the interests of all parties to a conflict and may resolve those conflicts by making decisions that benefit Enbridge and its shareholders or Enbridge Management and its shareholders more than us and our unitholders. The following decisions, among others, could involve conflicts of interest:

 

   

whether we or Enbridge will pursue certain acquisitions or other business opportunities;

 

48


Table of Contents
   

whether we will issue additional units or other equity securities or whether we will purchase outstanding units;

 

   

whether Enbridge Management or Enbridge Partners will issue additional shares or other equity securities;

 

   

the amount of payments to Enbridge and its affiliates for any services rendered for our benefit;

 

   

the amount of costs that are reimbursable to Enbridge Management or Enbridge and its affiliates by us;

 

   

the enforcement of obligations owed to us by Enbridge Management, our General Partner or Enbridge, including obligations regarding competition between Enbridge and us; and

 

   

the retention of separate counsel, accountants or others to perform services for us and Enbridge Management.

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

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

 

   

Enbridge and its subsidiaries are not restricted from continuing to engage in businesses, including the normal development of such businesses, in which they were engaged at the time of our initial public offering in December 1991;

 

   

such restriction is limited geographically only to those routes and products for which we provided transportation at the time of our initial public offering;

 

   

Enbridge and its subsidiaries are not prohibited from acquiring any business that materially and directly competes with us as part of a larger acquisition, so long as the majority of the value of the business or assets acquired, in Enbridge’s reasonable judgment, is not attributable to the competitive business; and

 

   

Enbridge and its subsidiaries are not prohibited from acquiring any business that materially and directly competes with us if that business is first offered for acquisition to us and the board of directors of Enbridge Management and our unitholders determine not to pursue the acquisition.

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

 

49


Table of Contents

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

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

 

   

The amount available for distributions on each unit may decrease;

 

   

The relative voting power of each previously outstanding unit may decrease; and

 

   

The market price of the Class A common units may decline.

Additionally, the public sale by our General Partner of a significant portion of the Class A or Class B common units, Class D units, Class E units or Series 1 preferred units that it or its subsidiary currently owns could reduce the market price of the Class A common units. Our partnership agreement allows the General Partner to cause us to register for public sale any units held by the General Partner or its affiliates. A public or private sale of the Class A or Class B common units, Class D units, Class E units or Series 1 preferred units currently held by our General Partner or its subsidiary could absorb some of the trading market demand for the outstanding Class A common units.

Holders of our limited partner interests have limited voting rights.

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

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

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

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

We are a holding company with no material operations. If we cannot receive cash distributions from our operating subsidiaries, we will not be able to meet our debt service obligations. Our operating subsidiaries may

 

50


Table of Contents

from time to time incur additional indebtedness under agreements that contain restrictions, which could further limit each operating subsidiaries’ ability to make distributions to us.

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

 

   

general creditors;

 

   

trade creditors;

 

   

secured creditors;

 

   

taxing authorities; and

 

   

creditors holding guarantees.

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

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

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

The holders of our Series 1 Preferred Units, or Preferred Units, have a preferential right to distributions prior to distributions to the holders of our Class A common units. For the first eight full quarters ending June 30, 2015, the quarterly cash distributions will not be payable on the Preferred Units and instead accrue and accumulate and are payable on the earlier of May 8, 2018 or on our redemption of the Preferred Units. Thereafter, the distributions will be paid in cash on a quarterly basis. To the extent that we do not pay in full any distribution on the Preferred Units, the unpaid amount will accrue and accumulate until it is paid in full, and no distributions may be made on the common units during that time.

RISKS ARISING FROM OUR PARTNERSHIP STRUCTURE

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

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates through the policy renewal date of May 1, 2015. The comprehensive insurance program also includes property insurance coverage on our assets, except pipeline assets that are not located at water crossings, including earnings interruption resulting from an insurable event. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement the Partnership has entered into with Enbridge, MEP, and another Enbridge subsidiary.

 

51


Table of Contents

RISKS RELATED TO OUR DEBT AND OUR ABILITY TO MAKE DISTRIBUTIONS

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

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

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

 

   

incurring additional debt;

 

   

entering into mergers or consolidations or sales of assets; and

 

   

granting liens.

Although the indentures governing our senior notes do not limit our ability to incur additional debt, they impose restrictions on our ability to enter into mergers or consolidations and sales of all or substantially all of our assets, to incur liens to secure debt and to enter into sale and leaseback transactions. A breach of any restriction under our Credit Facilities or our indentures could permit the holders of the related debt to declare all amounts outstanding under those agreements immediately due and payable and, in the case of our Credit Facilities, terminate all commitments to extend further credit. Any subsequent refinancing of our current debt or any new indebtedness incurred by us or our subsidiaries could have similar or greater restrictions.

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 taxes as corporations. An exception exists, however, with respect to

 

52


Table of Contents

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 to you. Therefore, if we were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation 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.

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

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

 

53


Table of Contents

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.

 

54


Table of Contents

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.

 

55


Table of Contents

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

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

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 over 22 states. Most of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Please consult your tax advisor.

Item 2.    Properties

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

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

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

 

56


Table of Contents

Item 3.    Legal Proceedings

We are a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We believe the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition. The disclosures included in Part II, Item 8. Financial Statements and Supplementary Data, under Note 13. Commitments and Contingencies, address the matters required by this item and are incorporated herein by reference.

Item 4.    Mine Safety Disclosures

None.

 

57


Table of Contents

PART II

 

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

Our Class A common units are listed and traded on the NYSE, the principal market for the Class A common units, under the symbol EEP. The quarterly price ranges per Class A common unit and cash distributions paid per unit for 2014 and 2013 are summarized as follows:

 

     First      Second      Third      Fourth  

2014 Quarters

           

High

   $ 29.94      $ 36.95      $ 40.10      $ 41.68  

Low

   $ 26.30      $ 26.00      $ 31.78      $ 31.63  

Cash distributions paid

   $ 0.54350      $ 0.54350      $ 0.55500      $ 0.55500  

2013 Quarters

           

High

   $ 30.68      $ 31.17      $ 33.49      $ 31.30  

Low

   $ 27.01      $ 28.01      $ 28.97      $ 28.41  

Cash distributions paid

   $ 0.54350      $ 0.54350      $ 0.54350      $ 0.54350  

On February 13, 2015, the last reported sales price of our Class A common units on the NYSE was $38.84. At January 30, 2015, there were approximately 80,524 Class A common unitholders, of which there were approximately 995 registered Class A common unitholders of record. There is no established public trading market for our Class B common units or Class D units, all of which are held by the General Partner, or our i-units, all of which are held by Enbridge Management.

 

58


Table of Contents
Item 6.    Selected Financial Data

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

 

     December 31,  
     2014     2013     2012     2011     2010  
    (in millions, except per unit amounts)  

Income Statement Data:

         

Operating revenues(6)(9)

  $ 7,964.7     $ 7,117.1     $ 6,706.1     $ 9,109.8     $ 7,736.1  

Operating expenses(6)(7)(8)(9)

    6,878.0       6,676.7       5,812.9       8,113.0       7,608.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    1,086.7       440.4       893.2       996.8       127.3  

Interest expense

    403.2       320.4       345.0       320.6       274.8  

Allowance for equity used during construction

    57.2       43.1       11.2             15.3  

Other income (expense)(10)

    8.9       16.0       (1.2     6.5       2.2  

Income tax expense

    9.6       18.7       8.1       5.5       7.9  

Noncontrolling interest

    263.3       88.3       57.0       53.2       60.6  

Series 1 preferred unit distributions

    90.0       58.2                    

Accretion of discount on Series 1 preferred units

    14.9       9.2                    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations attributable to general and limited partnership interests

  $ 371.8     $ 4.7     $ 493.1     $ 624.0     $ (198.5
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) allocable to common units and i-units

  $ 218.4     $ (122.7   $ 369.2     $ 520.5     $ (260.1
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per common unit and i-unit (basic)(1)

  $ 0.67     $ (0.39   $ 1.27     $ 1.99     $ (1.09
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per common unit and i-unit (diluted)(1)

  $ 0.67     $ (0.39   $ 1.27     $ 1.99     $ (1.09
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions paid per limited partner unit outstanding

  $     2.1970     $     2.1740     $     2.1520     $     2.0925     $     2.0240  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Financial Position Data (at year end):

         

Property, plant and equipment, net(7)(9)

  $ 15,692.7     $ 13,176.8     $ 10,937.6     $ 9,439.4     $ 8,641.6  

Total assets

    17,746.9       14,901.5       12,796.8       11,370.1       10,441.0  

Long-term debt, excluding current maturities(3)

    6,675.2       4,777.4       5,501.7       4,816.1       4,778.9  

Notes payable to General Partner

    306.0       318.0       330.0       342.0       347.4  

Partners’ capital:

         

Series 1 preferred units

    1,175.6       1,160.7                    

Class A common units(4)

    235.5       2,979.0       3,590.2       3,386.7       2,641.0  

Class B common units

          65.3       83.9       82.2       64.9  

Class D units(11)

    2,516.8                          

Incentive distribution units

    493.0              

i-units(5)(8)

    712.6       1,291.9       801.8       728.6       579.1  

General Partner

    198.3       301.5       299.0       285.6       256.8  

Accumulated other comprehensive income (loss)

    (211.4     (76.6     (320.5     (316.5     (121.7

Noncontrolling interest

    3,609.0       1,975.6       793.5       445.5       465.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital

  $ 8,729.4     $ 7,697.4     $ 5,247.9     $ 4,612.1     $ 3,885.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data:

         

Cash flows provided by operating activities(6)(7)(8)(9)

  $ 816.8     $ 1,212.4     $ 851.0     $ 1,045.6     $ 377.9  

Cash flows used in investing activities

    2,976.6       2,642.9       1,906.6       1,099.0       1,427.8  

Cash flows provided by financing activities(3)(4)(5)

    2,192.9       1,367.4       860.6       331.4       1,051.2  

Additions to property, plant and equipment, and acquisitions included in investing activities, net of cash acquired(2)

    2,933.8       2,410.8       1,739.9       1,091.8       1,429.5  

 

(1)

The allocation of net income (loss) to the General Partner in the following amounts has been deducted before calculating income (loss) from continuing operations per common unit and i-unit: 2014, $163.9 million; 2013, $144.1 million; 2012, $129.3 million; 2011, $104.5 million; and 2010, $61.6 million.

 

59


Table of Contents
(2) 

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

 

Date of Acquisition

  

Description of Acquisition

September 2010

   Acquisition of the Elk City system in Oklahoma and Texas.

 

(3) 

Our financial position and cash flow data include the effect of the following debt issuances and debt repayments:

 

Date of Debt Issuance

  

Debt Type

   Amount of
Debt Issuance
 

September 2014

   3.560% MEP Senior Notes    $ 75  

September 2014

   4.040% MEP Senior Notes    $ 175  

September 2014

   4.420% MEP Senior Notes    $ 150  

September 2011

   4.200% Senior Notes    $ 600  

September 2011

   5.500% Senior Notes    $ 150  

September 2010

   5.500% Senior Notes    $ 400  

March 2010

   5.200% Senior Notes    $     500   

 

  For the year ended December 31, 2014 we paid $200.0 million of our 5.350% senior notes.

 

  For the year ended December 31, 2013 we paid $200.0 million of our 4.750% senior notes.

 

  For the year ended December 31, 2012 we paid $100.0 million of our 7.900% senior notes.

 

  For the year ended December 31, 2011 we paid $31.0 million of our First Mortgage Notes.

 

  For the year ended December 31, 2010 we paid $31.0 million of our First Mortgage Notes.

 

(4) 

Our financial position and cash flow data include the effect of the following limited partner unit issuances:

 

Date of Unit Issuance

   Class of Limited
Partnership Interest
     Number of
Units
Issued
     Net Proceeds
Including General
Partner Contribution
 

September 2012

     Class A         16,100,000      $ 456.2  

May 2012

     Class A         64,464      $ 2.0  

2011 Equity Distribution Agreement issuances

     Class A         3,084,208      $ 95.5  

December 2011

     Class A         9,775,000      $ 298.1  

September 2011

     Class A         8,000,000      $ 222.9  

July 2011

     Class A         8,050,000      $ 238.6  

January 2011

     Class A         50,650      $ 1.6  

2010 Equity Distribution Agreement issuances

     Class A         2,237,402      $ 59.9  

November 2010

     Class A         11,960,000       $     354.8   

 

  All unit issuances prior to the April 2011 stock split have been retrospectively adjusted to be comparable.

 

  In January 2011 and May 2012 we issued Class A common units in connection with land acquisitions.

 

(5) 

Our income statement, financial position and cash flow data include the effect of the following distributions:

 

Fiscal Year

   Amount of  Distribution
of i-units to i-unit
Holders(a)
     Retained from
General Partner
     Distribution of
Cash
 

2014

   $ 143.9       $     3.0      $     727.8  

2013

   $ 113.8       $ 2.3      $ 708.9  

2012

   $ 85.0       $ 1.7      $ 660.3  

2011

   $ 75.7       $ 1.5      $ 565.7  

2010

   $ 68.3       $ 1.4      $ 481.6  

 

  (a) 

The quarterly in-kind distributions of 4.6 million, 3.8 million, 2.6 million, 2.4 million and 2.5 million i-units during 2014, 2013, 2012, 2011 and 2010, respectively were made to our General Partner in lieu of cash distributions.

 

(6) 

Operating results for the years ended December 31, 2014, 2013 and 2012, were affected by costs incurred in connection with the crude oil releases on Lines 6A and 6B of our Lakehead system. We estimate that in connection with these incidents for the years ended December 31, 2014, 2013, 2012 , 2011 and 2010 we accrued costs of $85.9 million, $302.0 million, $55.0 million, $218.0 million and $595.0 million, respectively, for emergency response, environmental remediation and cleanup activities associated with the crude oil releases, before insurance recoveries and excluding fines and penalties. In addition, for the years ended December 31, 2014, 2013, 2012 and 2011, we recognized $0.0 million, $42.0 million, $170.0 million and $335.0 million, respectively, in insurance recoveries related to such incidents. Furthermore, during the period the pipelines were not in service in 2010, our operating revenues were lower by

 

60


Table of Contents
  approximately $16 million as a result of the volumes that we were unable to transport. We do not maintain insurance coverage for interruption of our operations, except for water crossings, and therefore we will not recover the revenues lost while Lines 6A and 6B were not in service. Based on our current estimate of costs associated with these crude oil releases through December 31, 2014, Enbridge and its affiliates, including us, have exceeded the limits of coverage under this insurance policy; however we are in legal discussions to recover the remaining $103.0 million balance of our aggregate insurance coverage, but there can be no assurance that we will collect the remaining insurance balance.

 

(7) 

Operating results for the year ended December 31, 2011 were affected by $52.2 million we received in the second quarter of 2011 for the settlement of a dispute related to oil measurement losses, which we recognized as a reduction to operating expenses.

 

(8) 

Operating results for the year ended December 31, 2011 were affected by $18.0 million of additional expense we recognized in the fourth quarter of 2011, related to accounting misstatements and accounting errors. At our wholly-owned trucking and NGL marketing subsidiary, we identified accounting misstatements and other errors in early 2012 associated with the financial statement recognition of NGL product purchases and sales within our Natural Gas segment over a period from at least 2005 through 2011 prior to their detection in 2012.

 

(9) 

Operating results for the year ended December 31, 2012 were affected by $8.9 million of estimated costs accrued in connection with the July 27, 2012 crude oil release on Line 14 of our Lakehead system as discussed in Note 13. Commitments and Contingencies. The $10.5 million accrual is inclusive of approximately $1.6 million of lost revenue and excludes any potential fines or penalties. We will be pursuing claims under our insurance policy, although we do not expect any recoveries to be significant.

 

(10) 

Since October 2011, we and Enbridge have announced multiple expansion projects that will provide increased access to refineries in the United States Upper Midwest and in Canada in the provinces of, Ontario, and Quebec for light crude oil produced in western Canada and the United States. These projects collectively referred to as the Eastern Access Projects and Mainline Expansion Projects, will cost approximately $2.7 billion and $2.3 billion, respectively. These projects have been undertaken on a cost-of-service basis and are funded 75% by our General Partner and 25% by the Partnership under the Eastern Access Joint Funding Agreement and Mainline Expansion Joint Funding Agreement, as amended. In conjunction with our application of the provisions of regulatory accounting, we recorded allowance for equity during construction, or AEDC, of $54.7 million, $33.3 million and $4.7 million, for the years ended December 31, 2014 and 2013, and 2012 and respectively, which is recorded in “Other income” in our consolidated statements of income.

 

(11) 

July 1, 2014 we issued a total of 66.1 million Class D units, which are owned by a subsidiary of the General Partner. The Class D unites carry a distribution equal to the quarterly distribution on the Class A common units. The Class D units are convertible on a one-for-one basis into Class A common units at any time after the fifth anniversary of the closing date, at the holder’s option.

 

61


Table of Contents
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 beginning in Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

RESULTS OF OPERATIONS—OVERVIEW

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

 

   

Interstate pipeline transportation and storage of crude oil and liquid petroleum;

 

   

Gathering, treating, processing and transportation of natural gas and natural gas liquids, or NGLs, through pipelines and related facilities and supply, transportation and sales services, including purchasing and selling natural gas and NGLs.

We conduct our business through two business segments: Liquids and Natural Gas. During the first quarter of 2014, we changed our reporting segments. The Marketing segment was combined with the Natural Gas segment to form one new segment named “Natural Gas”. There was no change to the Liquids segment. These segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

In May 2013, we formed a new subsidiary, MEP. On November 13, 2013, MEP completed the Offering of Class A common units, representing limited partner interests in MEP. On the same date, in connection with the closing of the Offering, certain transactions, among others, occurred pursuant to which we effectively conveyed to MEP all of our limited liability company interests in the general partner of Midcoast Operating, and a 39% limited partner interest in Midcoast Operating, in exchange for certain MEP Class A common units and MEP Subordinated Units, approximately $304.5 million in cash as reimbursement for certain capital expenditures with respect to the contributed businesses, and a right to receive $323.4 million in cash. In addition, in connection with the Offering and the closing of the underwriters’ exercise of its over-allotment option, we received $47.0 million from MEP in its redemption of 2,775,000 of MEP Class A common units from us. At December 31, 2013, we owned 2.893% of the outstanding MEP Class A units, 100% of the outstanding MEP Subordinated Units, 100% of MEP’s general partner and 61% of the limited partner interests in Midcoast Operating.

On July 1, 2014, we sold an additional 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which reduced our total ownership interest in Midcoast Operating from 61% to 48.4%. This transaction represents our first sale to MEP of additional interests in Midcoast Operating since the Offering. We intend to sell additional interests in our natural gas assets, held through Midcoast Operating, to MEP and use the proceeds from any such sale as a source of funding for us. However, we do not know when, or if, any additional interests will be offered for sale.

 

62


Table of Contents

The following table reflects our operating income by business segment and corporate charges for each of the years ended December 31, 2014, 2013 and 2012:

 

     December 31,  
     2014     2013     2012  
     (in millions)  

Operating Income (loss)

      

Liquids

   $     938.9     $     392.6     $     706.8  

Natural Gas

     158.4       55.4       188.7  

Corporate, operating and administrative

     (10.6     (7.6     (2.3
  

 

 

   

 

 

   

 

 

 

Total Operating Income

     1,086.7       440.4       893.2  

Interest expense, net

     403.2       320.4       345.0  

Allowance for equity used during construction

     57.2       43.1       11.2  

Other income (loss)

     8.9       16.0       (1.2

Income tax expense

     9.6       18.7       8.1  
  

 

 

   

 

 

   

 

 

 

Net income

     740.0       160.4       550.1  

Less: Net income attributable to:

      

Noncontrolling interest

     263.3       88.3       57.0  

Series 1 preferred unit distributions

     90.0       58.2        

Accretion of discount on Series 1 preferred units

     14.9       9.2        
  

 

 

   

 

 

   

 

 

 

Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.

   $ 371.8     $ 4.7     $ 493.1  
  

 

 

   

 

 

   

 

 

 

Summary Analysis of Operating Results

Liquids

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

The operating income of our Liquids segment for the year ended December 31, 2014 increased $546.3 million, as compared with the same period in 2013, primarily due to the following:

 

   

Increased revenue of $339.5 million for the year ended December 31, 2014 related to rate increases as a result of tariff filings that became effective April 1, July 1, and August 1, 2014. The primary drivers of the increase were the additional Lakehead system expansion projects placed into service in 2014 and a full year of revenue for Lakehead and North Dakota expansion projects placed into service during 2013;

 

   

Increased volumes on our Lakehead and North Dakota systems increased revenue by $139.9 million for the year ended December 31, 2014;

 

   

Increased non-cash, mark-to-market net gains of $17.3 million related to derivative financial instruments for the year ended December 31, 2014. The increase is the result of $2.3 million in realized gains related to our settled derivative financial instruments, coupled with $15.0 million of non-cash, mark-to-market net gains due to decreases in average forward prices of crude oil;

 

63


Table of Contents
   

Increased revenue from our ship or pay agreements of $24.2 million on our North Dakota Bakken system for the year ended December 31, 2014;

 

   

Increased rail revenue of $17.6 million for the year ended December 31, 2014 on our Berthold Rail system that was placed into service in March of 2013; and

 

   

Decreased environmental expense of $176.4 million for the year ended December 31, 2014, primarily due to decreased environmental accruals, net of recoveries, related to the Line 6B crude oil release recognized in the second quarter of 2013.

The increase in operating income was partially offset by the following factors:

 

   

Increased operating and administrative expenses of $39.8 million primarily due to increases of $40.4 million of workforce related costs, $18.6 million of property taxes, and $34.3 million of other operating and administrative costs, which include contract labor, insurance, rents and lease payments, and professional and regulatory services. These cost increases were offset by $53.9 million of pipeline integrity costs. The decrease in pipeline integrity costs is primarily due to $57.7 million of costs incurred in the third quarter of 2013 for the Line 14 hydrostatic test that did not occur again during 2014. The increase in other operating and administrative costs is primarily the result of additional assets placed into service;

 

   

Increased power costs of $78.9 million for the year ended December 31, 2014, primarily due to an increase in volumes on our systems; and

 

   

Increased depreciation expense of $61.9 million for the year ended December 31, 2014, primarily attributable to additional assets placed into service.

Natural Gas

Our natural gas business includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities and NGL fractionation facilities, along with providing supply, transmission, storage and sales services to producers and wholesale customers on our natural gas gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Revenues for our natural gas 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. Additionally, we realize incremental revenue on gas purchased at the wellhead, increase pipeline utilization and provide other services that are valued by our customers. The segment gross margin of our natural gas business 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 operating income of our Natural Gas segment for the year ended December 31, 2014 increased $103.0 million, as compared with the year ended December 31, 2013, primarily due to the following:

 

   

Segment gross margin increased $161.5 million due to non-cash, mark-to-market net gains from derivative instruments that do not qualify for hedge accounting treatment, when compared to the same period in 2013;

 

   

Segment gross margin increased $15.6 million due to increased margins from higher commodity prices, net of hedges, related to contracts pursuant to which we are paid in commodities for our services;

 

   

Segment gross margin increased $2.3 million due to improved pricing spreads between the Conway and Mont Belvieu market hubs;

 

64


Table of Contents
   

Segment gross margin decreased approximately $45.8 million primarily due to reduced natural gas and NGL average daily volumes on our major systems primarily attributable to the loss of a major customer on our Anadarko system in 2013 and reduced and delayed drilling activity in the Anadarko and East Texas regions;

 

   

Segment gross margin decreased $33.4 million due to reduced keep-whole processing earnings;

 

   

Segment gross margin decreased approximately $3.0 million 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;

 

   

Operating and administrative costs decreased $11.2 million due primarily to decreased outside contract labor, lower rents and leases, and lower pipeline integrity costs offset by a non-cash asset impairment charge and an increase in costs due to separation costs associated with workforce reductions; and

 

   

Depreciation and amortization expense increased $8.3 million due to additional assets that were placed into service.

Derivative Transactions and Hedging Activities

Contractual arrangements in our Liquids and Natural Gas segments expose us to market risks associated with changes in commodity prices where we receive crude oil, natural gas or NGLs in return for the services we provide or where we purchase natural gas or NGLs. 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 (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 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. Some of these derivative financial instruments do not qualify for hedge accounting under the provisions of authoritative accounting guidance, which can 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 qualify for hedge accounting in our consolidated statements of income as follows:

 

   

Liquids segment commodity-based derivatives—“Transportation and other services” and “Power”

 

   

Natural Gas segment commodity-based derivatives—“Commodity sales” and “Commodity costs”

 

   

Corporate interest rate derivatives—“Interest expense”

 

65


Table of Contents

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 derivative fair value net gains and losses associated with the changes in fair value of our derivative financial instruments:

 

     December 31,  
     2014     2013     2012  
     (in millions)  

Liquids segment

      

Non-qualified hedges

   $ 13.6     $ (3.9   $ 1.3  

Natural Gas segment

      

Hedge ineffectiveness

     5.6       3.3       3.1  

Non-qualified hedges

     152.9       (6.3     (1.9
  

 

 

   

 

 

   

 

 

 

Commodity derivative fair value net gains (losses)

     172.1       (6.9     2.5  

Corporate

      

Interest Rate Hedge ineffectiveness

     (100.1     (21.5     (20.5

Non-qualified interest rate hedges

           (0.2     (0.5
  

 

 

   

 

 

   

 

 

 

Derivative fair value net gains (losses)

   $ 72.0     $ (28.6   $ (18.5
  

 

 

   

 

 

   

 

 

 

 

66


Table of Contents

RESULTS OF OPERATIONS—BY SEGMENT

Liquids

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

 

      December 31,  
      2014      2013      2012  
     (in millions)  

Operating Results

        

Operating revenue

   $ 2,070.4      $ 1,519.9      $ 1,345.8  
  

 

 

    

 

 

    

 

 

 

Environmental costs, net of recoveries

     97.3        273.7        (91.3

Operating and administrative

     500.8        461.0        371.5  

Power

     226.6        147.7        148.8  

Depreciation and amortization

     306.8        244.9        210.0  
  

 

 

    

 

 

    

 

 

 

Operating expenses

     1,131.5        1,127.3        639.0  
  

 

 

    

 

 

    

 

 

 

Operating income

   $ 938.9      $ 392.6      $ 706.8  
  

 

 

    

 

 

    

 

 

 

Operating Statistics

        

Lakehead system:

        

United States(1)

     1,669        1,427        1,405  

Province of Ontario(1)

     444        389        385  
  

 

 

    

 

 

    

 

 

 

Total Lakehead system delivery volumes(1)

     2,113        1,816        1,790  
  

 

 

    

 

 

    

 

 

 

Barrel miles (billions)

     582        487        480  
  

 

 

    

 

 

    

 

 

 

Average haul (miles)

     755        735        732  
  

 

 

    

 

 

    

 

 

 

Mid-Continent system delivery volumes(1)

     200        201        223  
  

 

 

    

 

 

    

 

 

 

North Dakota system:

        

Trunkline

     315        168        203  

Gathering

     3        3        3  
  

 

 

    

 

 

    

 

 

 

Total North Dakota system delivery volumes(1)

     318        171        206  
  

 

 

    

 

 

    

 

 

 

Total Liquids segment delivery volumes(1)

     2,631        2,188        2,219  
  

 

 

    

 

 

    

 

 

 

 

(1) 

Average barrels per day in thousands.

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

The operating revenue of our Liquids segment increased $550.5 million for the year ended December 31, 2014 when compared with the same period in 2013, primarily due to the filing of tariffs to increase the rates for our Lakehead, North Dakota and Ozark systems with the FERC. These rate increases became effective on April 1 and July 1, 2014 for our North Dakota and Ozark systems, and August 1, 2014 for our Lakehead system. The increase in rates accounted for $339.5 million of the increase in operating revenue for the year ended December 31, 2014 when compared to December 31, 2013. The large increase in rates is primarily due to $2.7 billion of additional assets placed into service in 2014 on the Lakehead system, including the Eastern Access, Mainline Expansion and other expansion projects. Additionally, 2014 revenues increased from a full year of revenue for Lakehead and North Dakota expansion projects placed into service during 2013. The rate increases effective April 1, 2014 primarily resulted from annual tariff filings for our North Dakota and Ozark systems to

 

67


Table of Contents

reflect our projected costs and throughput for 2014 and adjustments for the prior year. The rate increases effective July 1, 2014 resulted from an annual index rate filing to adjust base rates for our North Dakota and Ozark systems in compliance with rate ceilings allowed by the FERC. The rate increases effective August 1, 2014 resulted from tariff filings for our Lakehead system to reflect our projected costs and throughput for 2014, adjustments for the prior year, and an indexing adjustment to base rates in compliance with the indexed rate ceilings allowed by the FERC. Historically, the Lakehead system’s annual tariff filing has been effective April 1 and its annual index rate filing has been effective July 1; however, the filings were delayed due to negotiations with CAPP concerning certain components of the tariff rate structure. See Regulatory Matters of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for more information.

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

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

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

Additionally, operating revenue increased as a result of increases of $17.3 million of non-cash, mark-to-market net gains related to derivative financial instruments. The increase is the result of $2.3 million in realized gains related to our settled derivative financial instruments, coupled with $15.0 million of non-cash, mark-to-market net gains due to decreases in average forward prices of crude oil during 2014 compared to increases in the average forward prices of crude oil during 2013. We use forward contracts to hedge a portion of the crude oil we expect to receive from our customers as a pipeline loss allowance as part of the transportation of their crude oil. We subsequently sell this crude oil at market rates. We use derivative financial instruments which fix the sales price we will receive in the future for the sale of this crude oil. We elected not to designate these derivative financial instruments as cash flow hedges.

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

The operating and administrative expenses of our Liquids segment increased $39.8 million for the year ended December 31, 2014 when compared with the same period in 2013, primarily due to: $40.4 million of workforce related costs; $18.6 million of property taxes; and $34.3 million of other operating and administrative expenses, mainly consisting of contract labor, insurance, rents and lease payments, and professional and regulatory services. These cost increases primarily result from the additional assets placed into service during 2014. The increase in operating and administrative expenses is offset by a decrease of $53.9 million of pipeline integrity costs primarily due to $57.7 million of costs incurred for a hydrostatic test we performed on Line 14 during 2013 that did not occur again during 2014.

 

68


Table of Contents

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

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

Year ended December 31, 2013 compared with year ended December 31, 2012

The operating revenue of our Liquids segment increased $174.1 million for the year ended December 31, 2013 when compared with the same period in 2012, primarily due to the filing of tariffs that became effective July 1, 2013, April 1, 2013 and July 1, 2012 to increase the rates for our Lakehead, North Dakota and Ozark systems with the FERC. The increase in rates accounted for $157.4 million of the increase in operating revenue for the year ended December 31, 2013 when compared to December 31, 2012. The rate increases that became effective July 1, 2013 and July 1, 2012 resulted from an annual index rate filing to adjust rates in compliance with rate ceilings allowed by the FERC. The rate increase effective April 1, 2013 primarily resulted from the annual tariff filing for our Lakehead system to reflect our projected costs and throughput for 2013, adjustments for the prior year for the Lakehead system, and recovery of costs related to several of our major capital projects and System Expansion Program II, or SEP II, integrity costs on our Lakehead system.

Operating revenue also increased for the year ended December 31, 2013, when compared with the same period in 2012, due to an increase of $41.7 million in ship-or-pay contracts on our Bakken system. This is primarily due to an increase in volumes on the system for the year ended December 31, 2013, when compared with the same period in 2012, as the Bakken system was placed into service in March of 2013.

Additionally, our operating revenue increased during the year ended December 31, 2013, when compared to the same period in 2012, due to an increase of $19.4 million from our Berthold Rail System that was completed in March 2013. We also had increased operating revenue of $16.4 million from our storage facilities for the year ended December 31, 2013 as compared to 2012 primarily due to 1.3 million and 1.8 million barrels of tankage being placed into service at our Cushing facility during the second and fourth quarters of 2012 respectively.

The increase to operating revenue of our Liquids business for the year ended December 31, 2013 when compared with the same period in 2012 was offset by $29.7 million due to lower average daily delivery volumes on our North Dakota and Mid-Continent systems. The total average daily deliveries from our liquid systems decreased approximately 31,000 Bpd for the year ended December 31, 2013 as compared to the same year ended 2012. The decrease was partly driven by lower North Dakota volumes, which decreased due to unfavorable market pricing differentials between the East Coast and Gulf Coast markets. The decrease also relates to lower Mid-Continent volumes primarily resulting from pressure restrictions on our Mid-Continent system. Decreases on our North Dakota and Mid-Continent systems were offset by increased volumes on our Lakehead system due to the growth of the Canadian Oil Sands. The increase in operating revenue was also offset by $24.9 million as a result of regulatory adjustments related to Lakehead toll revenues. Delivery volume forecasts in the April 1, 2013 Lakehead toll filing were greater than actual volumes experienced, thus resulting in this negative impact. These amounts were adjusted and recovered in the Lakehead tariff that became effective August 1, 2014.

Additionally, our operating revenue decreased as a result of increases of $5.6 million of non-cash, mark-to-market net losses related to derivative financial instruments. We use forward contracts to hedge a portion of the crude oil we expect to receive from our customers as a pipeline loss allowance as part of the transportation of their crude oil. We subsequently sell this crude oil at market rates. We use derivative financial instruments which fix the sales price we will receive in the future for the sale of this crude oil. We elected not to designate these derivative financial instruments as cash flow hedges.

 

69


Table of Contents

Environmental costs, net of recoveries, increased $365.0 million for the year ended December 31, 2013 when compared with the same period in 2012, of which $375.0 million, net of recoveries, is related to the Line 6B crude oil release. During the year ended December 31, 2013, we recognized $42.0 million in insurance recoveries in connection with the Line 6B crude oil release compared to $170.0 million for the same period in 2012. We increased our total incident cost accrual by $302.0 million for the year ended December 31, 2013, compared to an increase of $55.0 million for the year ended December 31, 2012. This was offset by a decrease in environmental costs of $10.0 million related to other various crude oil releases for the year ended December 31, 2013 as compared to the same period in 2012.

The operating and administrative expenses of our Liquids segment increased $104.7 million for the year ended December 31, 2013 when compared with the same period in 2012 primarily due to $57.7 million of costs incurred for the Line 14 hydrostatic test we performed. After the July 27, 2012 release of crude oil on Line 14, the PHMSA issued a Corrective Action Order on July 30, 2012 and an amended Corrective Action Order on August 1, 2012, which we refer to collectively as the PHMSA Corrective Action Order. The PHMSA Corrective Action Order required us as part of an overall plan for our Lakehead system to take certain corrective actions, some of which were done during 2013 and others that are still ongoing. As part of this plan, we performed hydrostatic testing of Line 14 during the third quarter of 2013. Additionally, operating and administrative expenses for our Liquids segment also increased due to $14.7 million of increased workforce related costs, $10.2 million of increased property taxes, and $5.9 million of increased pipeline integrity costs.

The increase in depreciation expense of $34.9 million for the year ended December 31, 2013 is directly attributable to additional assets placed in service. Included in this change is a decrease of $4.2 million as a result of a depreciation study we completed during the fourth quarter of 2013 for our North Dakota and Ozark systems. The asset lives were extended due to additional reserve growth and pipeline connectivity needs. The impact on future periods is an annual reduction in depreciation expense of $16.8 million.

Future Prospects Update for Liquids

Our Lakehead system is well positioned as the primary transporter of Western Canadian crude oil and continues to benefit from the growing production of crude oil from the Alberta Oil Sands, as well as recent development in Tight Oil production in North Dakota. Based on growth in Western Canadian and Bakken crude oil production and other operational performance improvements, deliveries on our Lakehead system are expected to grow beyond the 2.1 million Bpd of average deliveries experienced during 2014. The ability to increase deliveries and to expand our Lakehead system in the future will ultimately depend upon a number of factors. The investment levels and related development activities by crude oil producers in conventional and oil sands production directly impacts the level of supply from the WCSB. Investment levels are influenced by crude oil producers’ expectations of crude oil and natural gas prices, future operating costs, U.S. demand and the availability of markets for produced crude oil. Higher crude oil production from the WCSB should result in higher deliveries on our Lakehead system. Deliveries on our Lakehead system are also negatively affected by periodic maintenance, other competitive transportation alternatives, or refinery turnarounds and other shutdowns at producing plants that supply crude oil.

Similar to our Lakehead system, our North Dakota system depends upon demand for crude oil in the Great Lakes and Midwest regions of the United States and the ability of crude oil producers to maintain their crude oil production and exploration activities. Due to increased exploration of the Bakken and Three Forks formations within the Williston Basin, the state of North Dakota reported production levels of 1,183,000 Bpd as of October 2014, with projections of stabilizing around that level or growing at a low rate due to current decreases in oil prices.

The chief transportation competition to our North Dakota system is rail. Initially considered a niche or alternative form of transportation, rail currently represents more than 59% of the total Bakken crude exported from North Dakota. Rail provides some advantages to pipeline transportation, but future Enbridge pipeline

 

70


Table of Contents

expansions and enhanced market access to Eastern Canadian markets and Eastern PADD II are reducing these advantages when it comes to shipping alternatives. As pipeline expansion projects create more export capacity from the Bakken and other pipeline projects provide increased access to more refinery markets across the United States, we expect North Dakota customers will shift volumes back to pipelines.

Of particular significance in 2014, Enbridge announced it is reviewing a potential restructuring plan that may involve the sale of some of its directly held U.S. liquids pipeline assets to us. The total estimated capital costs or net book value of Enbridge’s U.S. liquids pipeline assets that may ultimately be considered under the potential restructuring plan may exceed $10.0 billion. Enbridge’s U.S. liquids pipeline systems are extensive and include very strategic assets such as the Flanagan South, Spearhead, Seaway, Toledo, and Southern Access Extension pipelines. In addition, we have jointly funded with Enbridge several major expansions of the Lakehead pipeline system in the Great Lakes region of the United States. Enbridge’s review of a potential restructuring plan is underway and has not progressed to a conclusion. In the event that we receive a proposal from Enbridge, the Board of Directors of Enbridge Energy Management, L.L.C., the delegate of the General Partner would appoint a special committee comprised of independent directors to review and consider any such proposal. Acceptance of a proposal is subject to the review and favorable recommendation by the special committee and final approval by the Board.

Impact of Commodity Price Declines

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

The relatively high costs and large up-front capital investments required by oil sands projects involves significant assumptions around short-term and long-term crude oil fundamentals, including world supply and demand, North American supply and demand, and price outlook, among many other factors. As oil sands production is long-term in nature, the long-term outlook is significant to a producer’s investment decision. Short-term decisions may impact the annual rate of future supply growth from the oil sands region.

We expect that the current crude oil price downturn may result in deferral of some oil sands projects, particularly if the current pricing environment continues throughout 2015 and into 2016. However, we expect that projects already under construction will be finished and enter production. In addition, current production volumes from the oil sands are unlikely to decrease absent an operational upset at one of the oil sands operations. Accordingly, we do not anticipate significant changes in our short-term crude oil volume outlook. Our long-term growth in volumes and additional infrastructure expansion will depend on long-term fundamentals. During this period of uncertainty, we believe our pipeline systems are ideal to capture incremental pipeline capacity needs with lower cost, smaller scale expansions of our large Lakehead, North Dakota and Mid-Continent pipeline systems.

Tight sands oil production in any basin in North America will be comparatively more sensitive to the short-term changes in commodity prices due to the production profile associated with tight sands oil wells. Accordingly, we expect a reduction in the growth rate for North American tight sands and shale oil growth. We believe that rail will be the source of transportation most directly impacted by any declines in production due to its comparatively higher cost relative to pipeline transportation.

Financial impacts to our pipeline systems, in the event the rate of growth were to slow or volumes were to decline, is muted by our cost-of-service agreements, toll structures and demand to transport crude oil from existing production. We do not believe that the decline in crude oil prices will impact our liquids segment meaningfully in the short-term. However, a long-term decline in crude oil prices could have a more significant impact on future production and our rate of growth.

 

71


Table of Contents

We are continuing progress on additional construction to increase markets available to our shippers. Construction activity has become very challenging for Enbridge and us due to increased regulatory requirements. This could extend the time required for us to complete our projects. The table and discussion below summarize our commercially secured projects for the Liquids segment, which have been recently placed into service or will be placed into service in future periods:

 

Projects

   Total Estimated
Capital Costs
     In-Service Date     Funding  
     (in millions)               

Eastern Access Projects

       

Line 5, Line 62 Expansion, Line 6B Replacement

   $ 2,400        2013—2014 (4)      Joint (1) 

Eastern Access Upsize—Line 6B Expansion

     310        Early 2016        Joint (1) 

U.S. Mainline Expansions

       

Line 61 (ME phase 1)

     160        Q3 2014        Joint (2) 

Line 67 (ME phase 1)

     220        Q3 2014 (3)      Joint (2) 

Line 78 (Chicago Area Connectivity)

     495        Q3 2015        Joint (2) 

Line 61 (ME phase 2)

     1,155        2015—2017        Joint (2) 

Line 67 (ME phase 3)

     240        Second half 2015        Joint (2) 

Line 6B 75-mile Replacement Program

     390        Q2 2013—Q1 2014        EEP   

Sandpiper Project

     2,600        2017       Joint (5) 

Line 3 Replacement Program

     2,600        Late 2017        EEP (6) 

 

(1)

Jointly funded 25% by the Partnership and 75% by our General Partner under Eastern Access Joint Funding agreement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

 

(2)

Jointly funded 25% by the Partnership and 75% by our General Partner under Mainline Expansion Joint Funding agreement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

 

(3)

A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with the delays in regulatory approvals for the cross border expansion.

 

(4)

As of December 31, 2014, all projects in this phase have been put into service.

 

(5)

Since November 25, 2013, the Sandpiper Project is funded 62.5% by us and 37.5% by Williston Basin Pipeline LLC, an affiliate of Marathon Petroleum Corp., under the North Dakota Pipeline Company Amended and Restated Limited Liability Company Agreement.

 

(6)

A special committee of independent directors of the Board of Enbridge Management has been established to consider a joint funding agreement with Enbridge Inc.

Line 3 Replacement Program

On March 3, 2014, we and Enbridge announced that shipper support was received to replace portions of the existing 1,031-mile Line 3 pipeline on the Canadian Mainline/Lakehead system between Hardisty, Alberta, Canada and Superior, Wisconsin. Our portion of the Line 3 Replacement Program, referred to as the US L3R Program, includes replacing 358 miles from the U.S./Canadian border at Neche, North Dakota to Superior, Wisconsin. Subject to regulatory and other approvals, the US L3R Program is targeted to be completed in late 2017 at an estimated cost of $2.6 billion. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it supports the safety and operational reliability of the system, enhances flexibility and will allow us and Enbridge to optimize throughput from Western Canada into Superior, Wisconsin. The L3R Program is expected to achieve an equivalent 34-inch diameter pipeline capacity of approximately 760,000 bpd.

The initial term of the agreement is 15 years. For purposes of the toll surcharge, the agreement specifies a 30 year recovery of the capital based on a cost of service methodology. A special committee of independent directors of the board of Enbridge Management has been established to consider a proposal from our General Partner, on behalf of Enbridge, that would establish joint funding arrangements for the US L3R Program by creating an additional jointly owned series of partnership interests in Enbridge Energy, Limited Partnership, or OLP, similar to the series established for Alberta Clipper, Eastern Access and Mainline Expansion.

 

72


Table of Contents

Line 6B 75-mile Replacement Program

In 2011, we announced plans to replace 75-miles of non-contiguous sections of Line 6B of our Lakehead system. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments have been completed in components, with approximately 65 miles of segments placed in service in 2013. The two remaining 5-mile segments in Indiana were placed in service in March 2014. The total capital for this replacement program was approximately $390 million. These costs are currently being recovered through our FSM.

Light Oil Market Access Program

On December 6, 2012, we and Enbridge announced our plans to invest in a Light Oil Market Access Program to expand access to markets for growing volumes of light oil production. This program responds to significant recent developments with respect to supply of light oil from U.S. north central formations and western Canada, as well as refinery demand for light oil in the U.S. Midwest and eastern Canada. The Light Oil Market Access Program includes several projects that will provide increased pipeline capacity on our North Dakota regional system, further expand capacity on our U.S. mainline system, upsize the Eastern Access Project, enhance Enbridge’s Canadian mainline terminal capacity and provide additional access to U.S. Midwestern refineries.

Sandpiper Project

Included in the Light Oil Market Access Program is the Sandpiper Project which will expand and extend the North Dakota feeder system by 225,000 Bpd to a total of 580,000 Bpd. The proposed expansion will involve construction of an approximate 600-mile pipeline from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line will twin the existing 210,000 Bpd North Dakota system mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 250,000 Bpd of capacity on the twin line between Tioga and Berthold, North Dakota and 225,000 Bpd of capacity on the twin line between Berthold and Clearbrook both with a new 24-inch diameter pipeline, in addition to adding 375,000 Bpd between Clearbrook and Superior with a 30-inch diameter pipeline. The Sandpiper project is expected to cost approximately $2.6 billion.

In November 2013, we announced that Marathon Petroleum Corporation, or MPC, has been secured as an anchor shipper for the Sandpiper project. As part of the arrangement, we, through our subsidiary, North Dakota Pipeline Company LLC, or NDPC and Williston Basin Pipeline LLC, or Williston, an affiliate of MPC, entered into an agreement to, among other things, admit Williston as a member of NDPC. Williston will fund 37.5% of the Sandpiper Project construction and have the option to participate in other growth projects within NDPC, unless specifically excluded by the agreement; this investment is not to exceed $1.2 billion in aggregate. In return for funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in-service date of Sandpiper. Previously, we stated that the estimated target in-service date for our Sandpiper pipeline project would be in early 2016. We now estimate that the in-service date for the Sandpiper pipeline project will occur during 2017, subject to obtaining regulatory and other approvals. The delay is a result of a longer than expected permitting process in the State of Minnesota.

We filed a petition with the FERC to approve recovering Sandpiper’s costs through a surcharge to the NDPC rates between Beaver Lodge and Clearbrook and a cost of service structure for rates between Clearbrook and Superior. In March 2013, the FERC denied the petition on procedural grounds. We refiled the petition on February 12, 2014 and received approval in the form of a declaratory order from the FERC on May 16, 2014. Furthermore, in late 2013, we held an open season to solicit commitments from shippers for capacity created by the Sandpiper Project. The open season closed in late January 2014 with the receipt of a further capacity commitment which can be accommodated within the planned incremental capacity as identified above.

 

73


Table of Contents

Eastern Access Projects

Since October 2011, we and Enbridge have announced multiple expansion projects that will provide increased access to refineries in the U.S. Upper Midwest and the Canadian provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States. In 2013, we completed and placed into service the 50,000 Bpd capacity expansion of our Line 5 light crude line between Superior, Wisconsin and the international border at the St. Clair River. Furthermore in 2013, we completed and placed into service the expansion of the Spearhead North pipeline, or Line 62 expansion, between Flanagan, Illinois and the Terminal at Griffith, Indiana. The Line 62 expansion increased capacity from 130,000 Bpd to 235,000 Bpd by adding horsepower.

In 2012, we announced plans to replace additional sections of the our Line 6B in Indiana and Michigan, referred to as the Line 6B Replacement project, including the addition of new pumps and terminal upgrades at Hartsdale, Griffith and Stockbridge, as well as tanks at Flanagan, Stockbridge and Hartsdale, to increase capacity from 240,000 Bpd to 500,000 Bpd. The replacement of the Line 6B sections are in addition to the line 6B 75-Mile Replacement Program discussed above. Portions of the existing 30-inch diameter pipeline have been replaced with 36-inch diameter pipe. The target in-service date for the Line 6B Replacement project was split into two phases, with the segment between Griffith and Stockbridge completed in May 2014 and the segment from Ortonville, Michigan to the international border at the St. Clair River completed in September 2014. These completed projects cost us approximately $2.4 billion and are being undertaken on a cost-of-service basis with shared capital cost risk, such that the toll surcharge will absorb 50% of any cost overruns over $1.85 billion during the Competitive Toll Settlement, or CTS, term, which runs until July 2021.

As part of the Light Oil Market Access Program announced in 2012, we announced a further expansion project of Line 6B to increase capacity from 500,000 Bpd to 570,000 Bpd and will include pump station modifications at Griffith, Niles and Mendon, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. The expected cost of this expansion is approximately $310 million, which is a decrease of $55 million from the original estimated cost as a result of a more detailed engineering estimate and a proposed tank construction being removed from the scope of the project. This further expansion of Line 6B is expected to begin service in early 2016.

These projects, collectively referred to as the Eastern Access Projects, will cost approximately $2.7 billion. The Eastern Access Projects are now being funded at 75% by our General Partner and 25% by us under the Eastern Access Joint Funding Agreement, after we exercised the option to reduce our portion of the funding by 15% on June 28, 2013. Additionally, within one year of the in-service date, scheduled for early 2016, we will have the option to increase our economic interest by up to 15% at cost.

U.S. Mainline Expansions

In 2012 and 2013, we announced further expansion projects for our mainline pipeline system including: (1) expanding our existing 36-inch diameter Alberta Clipper pipeline, or Line 67; (2) expanding of the existing 42-inch diameter Southern Access pipeline, or Line 61; and (3) expanding by constructing Line 78, a twin of the Spearhead North pipeline, or Line 62. These projects require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction.

The initial phase of the Line 67 pipeline expansion includes increasing capacity between Neche, North Dakota into the Superior, Wisconsin Terminal from 450,000 Bpd to 570,000 Bpd at an estimated cost of approximately $220 million, while the second phase will add an additional 230,000 Bpd of capacity at an estimated cost of approximately $240 million. These projects require only the addition of pumping horsepower at existing sites, with no pipeline construction. Subject to regulatory and other approvals, including an amendment to the current Presidential border crossing permit to allow for operation of the Line 67 pipeline at its currently planned operating capacity of 800,000 Bpd through the border crossing segment, the expansions will be

 

74


Table of Contents

undertaken on a full cost-of-service basis. The initial phase was mechanically completed in the third quarter of 2014 and the second phase of the expansion is expected to be in-service in 2015. It is anticipated that obtaining Federal regulatory approval for the expansion to 800,000 Bpd will take longer than originally planned although approval is expected in the second half of 2015. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with the initial 120,000 bpd capacity increase as a result of the delays in regulatory approvals.

In November of 2014 several environmental and Native American groups filed a complaint in the United States District Court in Minnesota against the United States Department of State, or DOS. The Complaint alleges, among other things, that the DOS is in violation of the National Environmental Policy Act by acquiescing in Enbridge’s use of permitted cross border capacity on other lines to achieve the transportation of amounts in excess of the current permitted capacity of Alberta Clipper pending review and approval of Enbridge’s application to the DOS to increase the permitted cross border capacity of Alberta Clipper. Enbridge has moved to intervene in the case. A decision at the trial level is not expected before the third quarter of 2015.

The current scope of the Southern Access expansion, or Line 61 expansion, between Superior, Wisconsin and Flanagan, Illinois also consists of two phases. Both phases of the Line 61 expansion require only the addition of pumping horsepower with no pipeline construction. The initial phase of the Line 61 expansion was completed in August 2014 and increased capacity between the Superior Terminal and the Flanagan Terminal near Pontiac, Illinois from 400,000 Bpd to 560,000 Bpd at an estimated cost of approximately $160 million. The second phase of the Line 61 expansion will further expand the pipeline and add crude oil tankage at new and existing sites. The pipeline expansion will be split into two tranches. The first tranche will expand the pipeline capacity to 800,000 Bpd at a cost of approximately $395 million and is expected to be in service in the second quarter of 2015. Additional tankage is expected to cost approximately $360 million and is expected to be completed on various dates beginning in the second quarter of 2015 through early 2016. The second tranche, which remains subject to regulatory and other approvals, will expand the pipeline capacity to 1,200,000 Bpd at a cost of approximately $400 million. Management is exploring with shippers the potential to delay the in-service date of the final tranche of the Line 61 expansion to align more closely with the currently anticipated in-service date for the Sandpiper project, which will drive the need for additional downstream capacity.

Furthermore, as part of the Light Oil Market Access Program announced in 2012, the capacity on our Lakehead System between Flanagan, Illinois, and Griffith, Indiana will be expanded by constructing Line 78, a 79-mile, 36-inch diameter twin of the Spearhead North pipeline, or Line 62, with an initial capacity of 570,000 Bpd, at an estimated cost of $495 million. Subject to regulatory and other approvals, the expansion is expected to begin service in the third quarter of 2015.

These projects, collectively referred to as the U.S. Mainline Expansions projects, will cost approximately $2.3 billion and will be undertaken on a cost-of-service basis. Furthermore, these projects are jointly funded by our General Partner and us, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement. On June 28, 2013, we exercised our option to decrease our economic interest and funding of the U.S. Mainline Expansions projects from 40% to 25%. Within one year of the in-service date, scheduled for 2017, we will have the option to increase its economic interest held at that time by up to 15% at cost.

Canadian Eastern Access and Mainline Expansion Projects

The Eastern Access Projects and U.S. Mainline Expansions projects complement Enbridge’s strategic initiative of expanding access to new markets in North America for growing production from western Canada and the Bakken Formation.

Since October 2011, Enbridge also announced several complementary Eastern Access and Mainline Expansion Projects. These projects include: (1) reversal of Enbridge’s Line 9A in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario, which was completed and placed into

 

75


Table of Contents

service in August 2013; (2) construction of a 35-mile pipeline adjacent to Enbridge’s Toledo Pipeline, originating at our Line 6B in Michigan to serve refineries in Michigan and Ohio, which was completed and placed into service in May 2013; (3) reversal of Enbridge’s Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec; (4) an expansion of Enbridge’s Line 9 to provide additional delivery capacity within Ontario and Quebec; (5) expansions to add horsepower on existing lines on the Enbridge Mainline system from western Canada to the U.S. border, where the first phase of the expansion was mechanically completed in August 2014; and (6) modifications to existing terminal facilities on the Enbridge Mainline system, comprised of upgrading existing booster pumps, additional booster pumps and new tank line connections in order to accommodate additional oil volumes and enhance operational flexibility. The outstanding projects have various targeted in-service dates throughout 2015. In October 2014, the Canadian National Energy Board, or NEB, requested additional information regarding one of the 30 conditions imposed on the Line 9B reversal and Line 9 expansion project in March 2014. On October 23, 2014, Enbridge responded to the NEB describing Enbridge’s rigorous approach to risk management and isolation valve placement. On February 6, 2015, the NEB approved two conditions from its previous order and Enbridge filed for the Leave to Open from the NEB. Enbridge expects to place the Line 9B reversal and Line 9 expansion project into service in the second quarter of 2015. As a condition of the February 2015 approval, the NEB also imposed additional obligations to ensure optimal protection of the area’s water resources. These projects will enable growing light crude production from the Bakken shale and from Alberta to meet refinery needs in Michigan, Ohio, Ontario and Quebec. These projects will also provide much needed transportation outlets for light crude, mitigating the current discounting of supplies in the basins, while also providing more favorable supply costs to refiners currently dependent on crudes priced off of the Atlantic basin.

Enbridge United States Gulf Coast Projects and Southern Access Extension

One of our key strengths is our relationship with Enbridge. In 2011, Enbridge announced two major U.S. Gulf Coast market access pipeline projects, which, when completed, will pull more volume through our pipeline and may lead to further expansions of our Lakehead pipeline system. In addition, in 2012 Enbridge announced the Southern Access Extension, which will support the increasing supply of light oil from Canada and the Bakken into Patoka, Illinois.

Flanagan South Pipeline

Enbridge’s Flanagan South Pipeline project transports volumes into Cushing, Oklahoma and twins its existing Spearhead pipeline, which starts at the hub in Flanagan, Illinois, for the majority of the route and delivers volumes into the Cushing hub. The 590-mile, 36-inch diameter pipeline has a design capacity of approximately 600,000 Bpd and was placed into service on December 1, 2014. However, in the initial years, it is not expected to operate to its full design capacity. In August 2013, the Sierra Club and National Wildlife Federation, the Plaintiffs, filed a Complaint for Declaratory and Injunctive Relief, referred to as the Complaint, with the United States District Court for the District of Columbia, or the Court. The Complaint was filed against multiple federal agencies, or the Defendants, and included a request that the Court issue a preliminary injunction suspending previously granted federal permits and ordering Enbridge to discontinue construction of the project on the basis that the Defendants failed to comply with environmental review standards of the National Environmental Policy Act. In September 2013, Enbridge obtained intervener status and joined the Defendants in filing a response in opposition to the motion for preliminary injunction. The Plaintiffs’ request for preliminary injunction was denied by the Court in November 2013. A court hearing was held on February 21, 2014 concerning the merits of the Complaint against the Defendants. The Court ruled on August 18, 2014 dismissing all claims in favor of Enbridge and the federal agencies. The Sierra Club filed an appeal to the U.S. Court of Appeals, D.C. Circuit in mid-August 2014 and filed its opening brief on December 23, 2014. Enbridge and the Defendants filed their briefs on January 22, 2015. The Sierra Club filed its reply brief on February 8, 2015 and an oral argument will be subsequently scheduled.

 

76


Table of Contents

Seaway Crude Pipeline

In 2011, Enbridge completed the acquisition of a 50% interest in the Seaway Crude Pipeline System, or Seaway. Seaway is a 670-mile pipeline that includes a 500-mile, 30-inch pipeline long-haul system that was reversed in 2012 to enable transportation of oil from Cushing, Oklahoma to Freeport, Texas, as well as a Texas City Terminal and Distribution System that serves refineries in the Houston and Texas City areas of Texas. Seaway also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast and provided an initial capacity of 150,000 Bpd. Further pump station additions and modifications completed in January 2013 have increased the capacity to approximately 400,000 Bpd, depending upon the mix of light and heavy grades of crude oil.

In March 2012, based on additional capacity commitments from shippers, plans were announced to proceed with an expansion of the Seaway Pipeline through construction of a second line to more than double its capacity to 850,000 Bpd. In July 2014, this second line, or Seaway Pipeline Twin, was mechanically complete, line fill followed the completion of line fill for the Flanagan South Pipeline (discussed above) and the pipeline was put in service in December 2014. This 30-inch diameter pipeline follows the same route as the existing Seaway Pipeline. Also included in the scope of this second line, was a 65-mile, 36-inch diameter pipeline lateral from the Seaway Jones Creek facility to Enterprise Product Partners L.P.’s, or Enterprise Product’s, ECHO crude oil terminal, or ECHO Terminal, in Houston, Texas that was completed in January 2014. Furthermore, a third line, a 100-mile pipeline from Enterprise Product’s ECHO Terminal to the Port Arthur/Beaumont, Texas refining center, was mechanically completed in August 2014 to provide shippers access to the region’s heavy oil refining capabilities, with line fill completed in January 2015. The new 100-mile pipeline offers incremental capacity of 750,000 Bpd.

Southern Access Extension

In December 2012, Enbridge announced that it would undertake the Southern Access Extension project, which will consist of the construction of a 165-mile, 24-inch diameter crude oil pipeline from Flanagan to Patoka, Illinois, as well as additional tankage and two new pump stations. The initial capacity of the new line is expected to be approximately 300,000 Bpd. On July 1, 2014, Enbridge entered into an agreement with Lincoln Pipeline LLC, or Lincoln, an affiliate of MPC, to, among other things, admit Lincoln as a partner and participate in the Southern Access Extension. Lincoln has purchased a 35% equity interest in the project and will make additional cash contributions in accordance with the Southern Access Extension’s spend profile in proportion to its 35% interest. Subject to regulatory and other approvals, the project is expected to be placed into service in late 2015.

Other Matters

Line 14 Corrective Action Orders

After the July 27, 2012 release of crude oil on Line 14, the PHMSA issued a Corrective Action Order on July 30, 2012 and an amended Corrective Action Order on August 1, 2012, or the PHMSA Corrective Action Orders. The PHMSA Corrective Action Orders require us to take certain corrective actions, some of which have already been completed and some that are still ongoing, as part of an overall plan for our Lakehead system.

A notable part of the PHMSA Corrective Action Orders was to hire an independent third party pipeline expert to review and assess our overall integrity program. The third party assessment included organizational issues, response plans, training and systems. An independent third party pipeline expert was contracted during the third quarter of 2012 and their work is currently ongoing. The total cost of this plan is separate from the repair and remediation costs and is not expected to have a material impact on future results of operations.

Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. During the fourth quarter of 2013 we received approval

 

77


Table of Contents

from the PHMSA to remove the pressure restrictions and to return to normal operating pressures for a period of twelve months. In December 2014, PHMSA again considered the status of the pipeline in light of information acquired throughout 2014. On December 9, 2014, we received a letter from PHMSA approving our request to continue the normal operation of Line 14 without pressure restrictions.

Natural Gas

Our Natural Gas segment consists of natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities and NGL fractionation facilities along with providing supply, transmission, storage and sales services to producers and wholesale customers on our natural gas gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Our natural gas business consists of the following four systems:

 

   

Anadarko system: Approximately 3,100 miles of natural gas gathering and transportation pipelines, approximately 60 miles of NGL pipelines, seven active natural gas processing plants, five standby natural gas processing plants and one standby treating plant located in the Anadarko basin.

 

   

East Texas system: Approximately 4,100 miles of natural gas gathering and transportation pipelines, approximately 144 miles of NGL pipelines, four active natural gas processing plants, including two HCDP plants, seven active natural gas treating plants, two standby natural gas treating plants and one fractionation facility located in the East Texas basin.

 

   

North Texas system: Approximately 3,900 miles of natural gas gathering and transportation pipelines, approximately 29 miles of NGL pipelines, and seven active natural gas processing plants located in the Fort Worth basin.

 

   

Texas Express NGL system: A 35% interest in an approximately 593-mile NGL intrastate transportation mainline and a related NGL gathering system that consists of approximately 116 miles of gathering lines. The Texas Express NGL system commenced startup operations during the fourth quarter of 2013.

Our Natural Gas segment also derives part of its operating income from selling natural gas received from producers on our pipeline assets to customers utilizing the natural gas. A majority of the natural gas we purchase is produced in Texas markets where we have expanded access to several interstate natural gas pipelines over the past several years, which we can use to transport natural gas to primary markets where it can be sold to major natural gas customers.

In addition to the market access provided by our company-owned intrastate natural gas pipelines, our natural gas business also pays third-party storage facilities and pipelines for the right to store and transport natural gas for various periods of time. These contracts may be denoted as firm transportation capacity, firm storage, interruptible storage or parking and lending services. These various contract structures are used to allow access to additional markets, assist with balancing natural gas supply and end use market sales, mitigate risk associated with sales and purchase contracts, and to take advantage of price differential opportunities.

Natural gas purchased and sold by our Natural Gas segment is primarily priced at a published daily or monthly price index. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated margins result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. At their request, we will enter into long-term, fixed-price purchase or sales contracts with our customers and generally will enter into offsetting hedged positions under the same or similar terms

Our natural gas business is exposed to commodity price fluctuations because the natural gas purchased is generally priced using an index that is different from the pricing index at which the gas is sold. This price

 

78


Table of Contents

exposure arises from the relative difference in natural gas prices between the contracted index at which the natural gas is purchased and the index under which it is sold, otherwise known as the “basis spread.” The spread can vary significantly due to local supply and demand factors. Wherever possible, this pricing exposure is economically hedged using derivative financial instruments. However, the structure of these economic hedges often precludes our use of hedge accounting under authoritative accounting guidance, which can create volatility in the operating results of our Natural Gas segment.

To mitigate the demand charges associated with transportation agreements on third-party pipelines, we look for market conditions that allow us to lock in the price differential between the pipeline receipt point and pipeline delivery point. This allows us to lock in a fixed sales margin inclusive of pipeline demand charges. We accomplish this by transacting basis swaps between the index where the natural gas is purchased and the index where the natural gas is sold. By transacting a basis swap between those two indices, we can effectively lock in a margin on the combined natural gas purchase and the natural gas sale, mitigating our exposure to cash flow volatility that could arise in markets where transporting the natural gas becomes uneconomical. However, the structure of these transactions precludes our use of hedge accounting under authoritative accounting guidance, which can create volatility in the operating results of our Natural Gas segment.

For contracted storage, in order to mitigate the absolute price differential between the cost of injected natural gas and withdrawals of natural gas, as well as storage fees, the injection and withdrawal price differential is hedged by buying fixed price swaps for the forecasted injection periods and selling fixed price swaps for the forecasted withdrawal periods. When the injection and withdrawal spread increases or decreases in value as a result of market price movements, we can earn additional profit through the optimization of those hedges in both the forward and daily markets. Although all of these hedge strategies are sound economic hedging techniques, these types of financial transactions do not qualify for hedge accounting under authoritative accounting guidance. As such, the non-qualified hedges are accounted for on a mark-to-market basis, and the periodic change in their market value, although non-cash, will impact our operating results.

The following tables set forth the operating results of our Natural Gas segment and the approximate average daily volumes of natural gas throughput and NGLs produced on our systems for the years ended December 31, 2014, 2013, and 2012.

 

      December 31,  
      2014      2013      2012  
     (in millions)  

Operating revenues

   $ 5,894.3      $ 5,597.2      $ 5,360.3  
  

 

 

    

 

 

    

 

 

 

Commodity costs

     5,145.9        4,948.9        4,570.1  

Operating and administrative

     438.6        449.8        466.7  

Depreciation and amortization

     151.4        143.1        134.8  
  

 

 

    

 

 

    

 

 

 

Operating expenses

     5,735.9        5,541.8        5,171.6  
  

 

 

    

 

 

    

 

 

 

Operating income

   $ 158.4      $ 55.4      $ 188.7  
  

 

 

    

 

 

    

 

 

 

Operating Statistics (MMBtu/d):

        

East Texas

     1,030,000        1,153,000        1,266,000  

Anadarko

     827,000        949,000        1,017,000  

North Texas

     293,000        317,000        330,000  
  

 

 

    

 

 

    

 

 

 

Total

     2,150,000        2,419,000        2,613,000  
  

 

 

    

 

 

    

 

 

 

NGL Production (Bpd)

     83,675        88,236        97,428  
  

 

 

    

 

 

    

 

 

 

 

79


Table of Contents

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

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

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

Segment gross margin increased $15.6 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013 due to increased margins from natural gas pricing differentials in the first quarter of 2014. We benefited from the difference between market centers in the Mid-Continent supply areas and market area in the Midwest, which arose from higher than normal demand from winter weather in the Midwest.

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

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

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

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

Operating and administrative costs of our Natural Gas segment decreased $11.2 million for the year ended December 31, 2014, when compared to the year ended December 31, 2013 primarily related to reduced outside contract labor, and lower rents and leases. This decrease was offset by an increase in costs from a non-cash impairment on our non-core Louisiana propylene pipeline asset of $15.6 million. The impairment charge was taken following finalization of a contract restructuring with the primary customer. In addition, in December of 2014, the company took actions to reduce its costs through a workforce reduction, which increased severance costs by $4.8 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013.

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

 

80


Table of Contents

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.

Year ended December 31, 2013, compared with year ended December 31, 2012

The operating income of our natural gas business for the year ended December 31, 2013, decreased $133.3 million, as compared with the year ended December 31, 2012. The most significant area affected was Natural Gas segment gross margin, representing revenue less commodity costs, which decreased $141.9 million for the year ended December 31, 2013, as compared with the year ended December 31, 2012.

The gross margin for our Natural Gas segment was negatively affected by the reduction in gross margin derived from purchasing some of our NGLs at the Conway market hub and selling them at the Mont Belvieu market hub. On our Anadarko system, we purchase some NGLs at Conway hub prices and then have the ability to resell the NGLs at Mont Belvieu hub prices. For the year ended December 31, 2013, the prevailing price for NGLs increased approximately 6% per composite barrel at the Conway pricing hub, and decreased approximately 9% per composite barrel at the Mont Belvieu pricing hub, in each case as compared with the prevailing composite barrel prices for the year ended December 31, 2012. The gross margin of our Natural Gas segment decreased by approximately $57.0 million for the year ended December 31, 2013, when compared with the year ended December 31, 2012, due to the changes in NGL prices between these pricing hubs.

Reduced production volumes negatively affected gross margin by approximately $27.0 million for the year ended December 31, 2013. The average daily volumes of our major systems for the year ended December 31, 2013, decreased by approximately 194,000 MMBtu/d, or 7%, when compared to the year ended December 31, 2012. The average NGL production, for the year ended December 31, 2013, decreased by approximately 9,192 Bpd, or 9%, when compared to the year ended December 31, 2012. The decline in volumes is due to reduced drilling activity in our dry gas operating areas, predominately in East Texas, along with a recent trend of dry gas wells that have been drilled but not completed, and the loss of a major customer contract on our Anadarko system, which led to reduced volumes on the system in the second half of 2013. Additionally, extreme weather conditions for the year ended December 31, 2013 as compared to December 31, 2012 also contributed to the reduced volumes. During 2013, two different sustained freezing events negatively impacted volumes flows on our Anadarko, Elk City, and North Texas systems for a seven to ten day time period. Additionally, a localized fire at our Elk City plant took this asset offline during December 2013. Recent shifts in supply and demand fundamentals for NGLs, particularly ethane, have resulted in downward pressure on the current and forward prices for this commodity. As a result, of the lower prices for ethane during the year ended December 31, 2013, it was more profitable to operate most of the processing plants on our Anadarko system in ethane rejection mode, which results in lower NGL volumes, since ethane is sold as part of the natural gas stream.

A variable element of the operating results of our Natural Gas segment is derived from processing natural gas on our systems. Under percentage of liquids, or POL, contracts, we are required to pay producers a contractually fixed recovery of NGLs regardless of the NGLs we physically produce or our ability to process the NGLs from the natural gas stream. NGLs that are produced in excess of this contractual obligation in addition to the barrels that we produce under traditional keep-whole gas processing arrangements we refer to collectively as keep-whole earnings. Operating revenue less the commodity costs derived from keep-whole earnings for the year ended December 31, 2013, decreased $27.1 million from the year ended December 31, 2012. The decline in keep-whole earnings is the result of a decline in total NGL production.

Also contributing to the decrease in gross margin for the year ended December 31, 2013, were $7.2 million of additional revenues for gas plant allocation corrections recognized during the year ended December 31, 2012, with no similar corrections recognized for the year ended December 31, 2013. These allocation corrections related to measured volumes at one of our North Texas plants that were being improperly included as part of the NGL revenue allocation with third party producers.

 

81


Table of Contents

Another factor in the decrease to gross margin for the year ended December 31, 2013, was a decrease of approximately $8.0 million due to changes in estimate to actual adjustments for the year ended December 31, 2013, as compared to the year ended December 31, 2012. For our Natural Gas segment, we estimate our current month revenue and commodity costs to permit the timely preparation of our consolidated financial statements. As a result, each month we record an adjustment of the prior month’s estimate to equal the prior month’s actual data.

Operating income of our Natural Gas segment experienced non-cash, mark-to-market net losses of $4.2 million from December 31, 2012, to December 31, 2013, mostly due to changes in the average forward prices of natural gas, NGLs and condensate. The average forward and daily prices for natural gas and propane increased for the year ended December 31, 2013, compared to the year ended December 31, 2012.

Also contributing to the decrease in gross margin for the year ended December 31, 2013, was a decrease of approximately $4.0 million due to changes in physical measurement adjustments for the year ended December 31, 2013, as compared to the year ended December 31, 2012. Physical measurement adjustments 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.

Offsetting these decreases, was in increase in operating results primarily due to higher natural gas prices during the year ended 2013, when compared to the year ended December 31, 2012. This improved pricing environment led to additional opportunities to benefit from improved price differentials between market centers which enable us to increase our margins in certain circumstances. As a result, we generated a $6.5 million gain for the year ended December 31, 2013, as compared to a $2.3 million gain for the year ended December 31, 2012.

Also contributing to the increase in operating results for the year ended December 31, 2013, was the expiration of certain transportation fees for natural gas being transported on a third party pipeline. These transportation fees expired, effective June 30, 2012, and reduced natural gas expense by approximately $2.0 million for the year ended December 31, 2013, as compared to the year ended December 31, 2012.

Operating results for the prior year were positively affected by only $0.4 million of non-cash charges to inventory for the year ended December 31, 2013, compared to $2.0 million for the year ended December 31, 2012, which we recorded to reduce the cost basis of our natural gas inventory to net realizable value. Since we hedge our storage positions financially, these charges are recovered when the physical natural gas inventory is sold or the financial hedges are realized.

Operating and administrative costs of our Natural Gas segment decreased $16.9 million for the year ended December 31, 2013, when compared to the year ended December 31, 2012, primarily due to the following:

 

   

Decreased current year costs of $7.5 million for the investigation related to accounting misstatements at our trucking and NGL marketing subsidiary recorded in 2012, with no similar costs recorded during the year ended December 31, 2013;

 

   

Decreased operational related costs of $6.8 million due to favorable spending for rents, maintenance, supplies and other outside services for the year ended December 31, 2013, when compared to the year ended December 31, 2012; and

 

   

Decreased current year costs of $4.3 million for the prior year write down of surplus materials associated with deferred portions of a development project on our East Texas system that we do not expect to complete until production levels reach a sustainable level to support our expansion activities in the region. There were no similar costs recorded during the year ended December 31, 2013.

Depreciation expense for our Natural Gas segment increased $8.3 million, for the year ended December 31, 2013, compared with the year ended December 31, 2012, due to additional assets that were put in service during 2012 and 2013.

 

82


Table of Contents

Future Prospects for Natural Gas

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

Impact of Commodity Prices

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. Demand for these services depends on overall economic conditions and commodity prices. As a result of the recent decline in commodity prices, there has been a reduction in drilling activity from producers. We have largely mitigated our direct commodity risk through our hedging program. We have hedged over 80% and over 65% of our direct commodity exposure in 2015 and 2016, respectively. Despite our hedging program, we still bear indirect commodity price impacts as lower drilling activity impacts the volumes on our systems. We expect this indirect impact on our volumes to improve as prices improve.

We have completed several expansion projects and are currently constructing the following major expansion projects that are designed to increase natural gas processing, NGL production, residue gas and NGL transportation capacity.

Beckville Cryogenic Processing Plant

In April 2013, we announced plans to construct a cryogenic natural gas processing plant near Beckville in Panola County, Texas, which we refer to as the Beckville processing plant. This plant is expected to serve existing and prospective customers pursuing production in the Cotton Valley formation, which is comprised of approximately ten counties in East Texas, as well as the Eaglebine developments, and has been a steady producer of natural gas for decades. Production from this play typically contains two to three gallons of NGLs per thousand cubic feet, or Mcf, of natural gas. The region currently produces approximately 2.2 billion cubic feet per day, or Bcf/d, of natural gas with 73,000 Bpd of associated NGLs. Until recently, the primary exploitation method in the Cotton Valley formation has been vertical wells. Lower horizontal drilling costs, coupled with the latest fracturing technology, has brought significant interest back to this area. Economics associated with horizontal wells in the Cotton Valley formation compare favorably to other rich natural gas plays, which has encouraged producers to increase drilling activity in the region. We expect our Beckville processing plant to be capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs to accommodate the additional liquids-rich natural gas being developed within this geographical area in which our East Texas system operates. Related NGL takeaway infrastructure connecting the Beckville plan to third party NGL transportation systems has been completed. We estimate the cost of constructing the plant to be approximately $145.0 million and expect it to commence service early in the second quarter of 2015.

The project is funded by us and MEP based on our proportionate ownership percentages in Midcoast Operating, which was 61% and 39%, respectively, between November 13, 2013 and June 30, 2014 and 48.4% and 51.6%, respectively, after July 1, 2014.

 

83


Table of Contents

Eaglebine Gathering

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 and Eagle Ford formations. We have a series of projects and an acquisition in this play. We have commenced construction of a lateral and associated facilities that will 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. 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 9, 2015, MEP announced an agreement with New Gulf Resources, LLC, or NGR, to purchase NGR’s midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition consists of a natural gas gathering system that is currently in operation moving equity and third party production.

We estimate the cost of these projects and acquisitions described above to be approximately $160 million, of which $135.0 million is estimated to be spent in 2015. Funding is to be provided by us and MEP based on our proportionate ownership percentages in Midcoast Operating, which are 48.4% and 51.6%, respectively.

Corporate Activities

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

 

     December 31,  
     2014     2013     2012  
     (in millions)  

Operating Results:

      

General and administrative expenses

   $ 10.6     $ 7.6     $ 2.3  
  

 

 

   

 

 

   

 

 

 

Operating loss

     (10.6     (7.6     (2.3

Interest expense

     403.2       320.4       345.0  

Allowance for equity used during construction

     57.2       43.1       11.2  

Other income (expense)

     (4.3     17.5       (1.2

Income tax expense

     9.6       18.7       8.1  
  

 

 

   

 

 

   

 

 

 

Net loss

   $ (370.5   $ (286.1   $ (345.4
  

 

 

   

 

 

   

 

 

 

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

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

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

The 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 $9.1 million for the year ended 2014 compared to the same period in 2013, primarily due to a tax law that was passed in June 2013 in the State of Texas, referred to as House Bill 500,

 

84


Table of Contents

or HB 500. The law allows a pipeline company that transports oil, gas, or other petroleum products owned by others to subtract as COGS, its depreciation, operations and maintenance costs related to the services provided. Under the new law, we are allowed additional deductions against our income for Texas margin tax purposes.

Year ended December 31, 2013 compared with year ended December 31, 2012

The decrease in our net loss of $59.3 million was primarily due to a $24.6 million decrease in interest expense from the corresponding period in 2012. This decrease in interest expense is primarily due to an increase of $15.4 million in capitalized interest related to our capital projects and a decreased weighted average outstanding debt balance due to a decrease in the commercial paper balance and repayment of $200.0 million of senior unsecured notes.

The tax structure that exists in Texas imposes taxes that are based upon many, but not all, items included in net income. Our income tax expense of $18.7 million for the year ended 2013, is computed by applying a 0.5% Texas state income tax rate to modified gross margin, as defined by Texas state income tax laws, and $12.4 million related to a one-time increase to deferred income tax expense. For 2012, we had an income tax expense of $8.1 million, which we computed by applying a 0.5% Texas state income tax rate to modified gross margin.

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

Our primary source of short-term liquidity is provided by our $1.5 billion commercial paper program, which is supported by our $1.975 million multi-year unsecured revolving credit facility, which we refer to as the Credit Facility, and our $650 million credit agreement, which we refer to as the 364-Day Credit Facility. We refer to the 364-Day Credit Facility and the Credit Facility as our Credit Facilities. We access our $1.5 billion commercial paper program primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities.

As set forth in the following table, we had approximately $1.2 billion of liquidity available to us at December 31, 2014, to meet our ongoing operational, investment and financing needs, as well as the funding requirements associated with the environmental remediation costs resulting from the crude oil releases on Line 6B.

 

     EEP      MEP  
     (in millions)  

Cash and cash equivalents

   $ 197.9      $  

Total credit available under our Credit Facilities

     2,625.0         

Total credit available under MEP’s Credit Agreement

            850.0  

Less: Amounts outstanding under Credit Facilities

     1,160.0         

Less: Amounts outstanding under MEP’s Credit Agreement

            360.0  

Principal amount of commercial paper issuances

     612.3         

Letters of credit outstanding

     330.2         
  

 

 

    

 

 

 

Total

   $ 720.4      $ 490.0  
  

 

 

    

 

 

 

General

Our primary operating cash requirements consist of normal operating expenses, maintenance capital expenditures, funding requirements associated with environmental costs, distributions to our partners and payments associated with our risk management activities. We expect to fund our current and future short-term

 

85


Table of Contents

cash requirements for these items from our operating cash flows supplemented as necessary by issuances of commercial paper and borrowings on our Credit Facilities. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our Credit Facilities.

Our current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses through organic growth and targeted acquisitions. We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as retire our maturing and callable debt, first from operating cash flows and then from issuances of commercial paper and borrowings on our Credit Facilities. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities, although there can be no assurance that such financings will be available on favorable terms, if at all. In addition, we intend to sell additional interests in Midcoast Operating entity to MEP to raise capital over the course of the next several years. Although this is our intent, there is no assurance that any transactions will occur as they are subject to, among other things, obtaining agreement from MEP and the Board of Directors of its general partner on the commercial terms of such a sale. In the past, when we had attractive growth opportunities in excess of our own capital raising capabilities, the General Partner provided supplementary funding, or participated directly in projects, to enable us to undertake such opportunities. If in the future we have attractive growth opportunities that exceed capital raising capabilities, we could seek similar arrangements from the General Partner, but there can be no assurance that this funding can be obtained.

As of December 31, 2014, we had a working capital deficit of approximately $1.0 billion and approximately $1.2 billion of liquidity to meet our ongoing operational, investing and financing needs.

Capital Resources

Equity and Debt Securities

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

Series 1 Preferred Unit Purchase Agreement

On May 8, 2013, we issued and sold 48,000,000 of our preferred units, representing limited partner interests in us, or Preferred Units, for aggregate proceeds of approximately $1.2 billion. We used proceeds from the Preferred Unit issuance to repay commercial paper, to finance a portion of its capital expansion program relating to its core liquids and natural gas systems and for general partnership purposes.

The Preferred Units are entitled to annual cash distributions of 7.50% of the issue price, payable quarterly, which are subject to reset every five years. However, these quarterly cash distributions, during the first full eight quarters ending June 30, 2015, will accrue and accumulate, which we refer to as the Payment Deferral. Thus we will accrue, but not pay these amounts until the earlier of the fifth anniversary of the issuance of such Preferred Units or the redemption of such Preferred Units by us. The quarterly cash distribution for the three month period ended June 30, 2013, was prorated from May 8, 2013.

 

86


Table of Contents

On or after June 1, 2016, at the sole option of the holder of the Preferred Units, the Preferred Units may be converted into Class A Common Units, in whole or in part, at a conversion price of $27.78 per unit plus any accrued, accumulated and unpaid distributions, excluding the Payment Deferral, as adjusted for splits, combinations and unit distributions. At all other times, redemption of the Preferred Units, in whole or in part, is permitted only if: (1) the Partnership uses the net proceeds from incurring debt and issuing equity, which includes asset sales, in equal amounts to redeem such Preferred Units; (2) a material change in the current tax treatment of the Preferred Units occurs; or (3) the rating agencies’ treatment of the equity credit for the Preferred Units is reduced by 50% or more, all at a redemption price of $25.00 per unit plus any accrued, accumulated and unpaid distributions, including the Payment Deferral.

The Preferred Units were issued at a discount to the market price of the common units into which they are convertible. This discount totaling $47.7 million represents a beneficial conversion feature and is reflected as an increase in common and i-unit unitholders’ and General Partner’s capital and a decrease in Preferred Unitholders’ capital to reflect the fair value of the Preferred Units at issuance on the Partnership’s consolidated statement of partners’ capital for the twelve month period ended December 31, 2013. The beneficial conversion feature is considered a dividend and is distributed ratably from the issuance date of May 8, 2013 through the first conversion date, which is June 1, 2016, resulting in an increase in preferred capital and a decrease in common and subordinated unitholders’ capital.

Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit issuances for the year ended December 31, 2012. There were no issuances of Class A common units for the years ended December 31, 2014 and 2013.

 

Issuance Date

   Number of
Class A
common units
Issued
     Offering Price
per Class A
common unit
     Net Proceeds
to the
Partnership(1)
     General
Partner
Contribution(2)
     Net Proceeds
Including
General
Partner
Contribution
 
     (in millions, except units and per unit amounts)  

2012

           

September(3)

     16,100,000       $         28.64       $         446.8       $         9.4       $         456.2  
  

 

 

       

 

 

    

 

 

    

 

 

 

 

(1) 

Net of underwriters’ fees and discounts, commissions and issuance expenses if any.

 

(2) 

Contributions made by the General Partner to maintain its 2% general partner interest.

 

(3) 

The proceeds from the September 2012 equity issuance were used to fund a portion of our capital expansion projects and for general partnership purposes.

Midcoast Energy Partner, L.P.

On November 13, 2013, MEP, a subsidiary of EEP, completed the Offering of 18,500,000 Class A common units representing limited partner interests and subsequently issued an additional 2,775,000 Class A common units pursuant to the underwriter’s over allotment option. MEP received proceeds (net of underwriting discounts, structuring fees and offering expenses) from the Offering of approximately $354.9 million. MEP used the net proceeds to distribute approximately $304.5 million to EEP, to pay approximately $3.4 million in revolving credit facility origination and commitment fees and used approximately $47.0 million to redeem 2,775,000 Class A common units from EEP. At December 31, 2014, we owned 5.9% of outstanding MEP Class A common units, 100% of the outstanding MEP Subordinated Units, 100% of MEP’s general partner and 48.4% of the limited partner interests in Midcoast Operating.

On July 1, 2014, we sold a 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which reduced our total ownership interest in Midcoast Operating from 61% to 48.4%. This transaction

 

87


Table of Contents

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

Investments

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

Available Credit

Our two primary sources of liquidity are provided by our commercial paper program and our Credit Facilities. We have a $1.5 billion commercial paper program that is supported by our Credit Facilities, which we access primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities. At December 31, 2014, we had approximately $522.5 million in available credit under the terms of our Credit Facilities. For a description of our commercial paper program and our Credit Facilities, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

Credit Facilities

In September 2011, we entered into a multi-year senior unsecured revolving credit facility, which we refer to as the Credit Facility. The Credit Facility permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion, a letter of credit subfacility and a swing line subfacility.

On October 6, 2014, we amended our Credit Facility to extend the maturity date to September 26, 2019; however, $175.0 million of commitments will expire on the original maturity date of September 26, 2018.

On July 6, 2012, we entered into a 364-day credit agreement, which we refer to as the 364-Day Credit Facility. The agreement is a committed senior unsecured revolving credit facility that originally permitted aggregate borrowings of up to, at any one time outstanding, $675.0 million subject to the terms and conditions set forth therein. The 364-Day Credit Facility provides aggregate lending commitments: (1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion, and (2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods.

On July 3, 2013, we amended our 364-Day Credit Facility, to extend the revolving credit termination date to July 4, 2014 and to increase aggregate commitments under the facility by $50.0 million. Furthermore, on July 24, 2013, we further amended the 364-Day Credit Facility, by adding a new lender and increased our aggregate commitments by another $50.0 million. On July 3, 2014, we amended our 364-Day Credit Facility to extend the revolving credit termination date to July 3, 2015, and to decrease aggregate commitments under the facility to $650.0 million

On October 28, 2013, we amended our Credit Facilities to modify certain terms and conditions to accommodate the Offering and the transactions contemplated thereby. The amendments were effective November 13, 2013.

 

88


Table of Contents

Our Credit Facilities provided an aggregate amount of approximately $2.625 billion of bank credit, as of December 31, 2014, which we use to fund our general activities and working capital needs.

As of December 31, 2014, we were in compliance with the terms of all of our financial covenants under the Credit Facilities. For further details regarding the Credit Facilities and the amendments thereto, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

On February 3, 2014, EEP entered into an uncommitted letter of credit arrangement, pursuant to which the bank may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request in an aggregate amount not to exceed $200.0 million. On September 9, 2014, the amount was increased to $220.0 million. While the letter of credit arrangement is uncommitted and issuance of letters of credit is at the bank’s sole discretion, we view this arrangement as liquidity enhancement as it allows EEP to potentially reduce its reliance on utilizing the committed Credit Facilities for issuance of letters of credit to support its hedging activities.

Commercial Paper

We have a commercial paper program that provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper and is supported by our Credit Facilities. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our Credit Facilities. At December 31, 2014, we had $612.3 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.50%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net borrowings of approximately $312.1 million during the twelve month period ended December 31, 2014, which includes gross borrowings of $11.2 billion and gross repayments of $10.9 billion. At December 31, 2013, we had $300.0 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.37%, excluding the effect of our interest rate hedging activities. Our policy is that the commercial paper we can issue is limited by the amounts available under our Credit Facility up to an aggregate principal amount of $1.5 billion. For further details regarding the commercial paper program, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. It is our policy to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at such time. Taking that policy into account, at December 31, 2014, we could borrow approximately $522.5 million under the terms of our Credit Facilities, determined as follows:

 

     (in millions)  

Total credit limit under Credit Facilities

   $   2,625.0  

Less: Amounts outstanding under Credit Facilities

      

Principal amount of commercial paper outstanding

     612.3  

Credit Facilities

     1,160.0  

Letters of credit outstanding

     330.2  
  

 

 

 

Total amount available at December 31, 2014

   $ 522.5  
  

 

 

 

On January 29, 2015, the board of directors of Enbridge Management constituted a committee of independent directors to evaluate a potential new 364-day credit agreement with Enbridge for up to $750.0 million. If approved, the proposed facility will provide us additional standby financing capability and flexibility to seek financing in the capital markets on reasonable terms.

 

89


Table of Contents

Senior Notes

All of our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $200.0 million of senior notes issued by the OLP, which we refer to as the OLP Notes. The OLP, our operating subsidiary that owns the Lakehead system, has $200.0 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes. The OLP Notes consist of $100.0 million of 7.000% senior notes due 2018 and $100.0 million of 7.125% senior notes due 2028. All of the OLP Notes pay interest semi-annually.

The OLP Notes do not contain any covenants restricting us from issuing additional indebtedness by the OLP. The OLP Notes are subject to make-whole redemption rights and were issued under an indenture, referred to as the OLP Indenture, containing certain covenants that restrict our ability, with certain exceptions, to sell, convey, transfer, lease or otherwise dispose of all or substantially all of our assets, except in accordance with the OLP Indenture. We were in compliance with these covenants at December 31, 2014. For further details regarding the senior notes, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

Junior Subordinated Notes

The $400.0 million in principal amount of our fixed/floating rate, junior subordinated notes due October 1, 2067, which we refer to as the Junior Notes, represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness. The Junior Notes bear interest at a fixed annual rate of 8.05%, exclusive of any discounts or interest rate hedging activities, payable semi-annually in arrears on April 1 and October 1 of each year until October 1, 2017. After October 1, 2017, the Junior Notes will bear interest at a variable rate equal to the three-month London Interbank Offered Rate, or LIBOR, for the related interest period increased by 3.7975%, payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2018. For further details regarding the junior subordinated notes, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

MEP Credit Agreement

On November 13, 2013, in connection with the closing of the Offering, MEP, Midcoast Operating, and their material domestic subsidiaries, entered into a Credit Agreement, which we refer to as the MEP Credit Agreement, by and among MEP, as co-borrower and a guarantor, Midcoast Operating, as co-borrower and a guarantor, MEP’s material subsidiaries party thereto as guarantors, Bank of America, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto.

The MEP Credit Agreement is a committed senior revolving credit facility (with related letter of credit and swing line facilities) that permits aggregate borrowings of up to, at any one time outstanding, $850.0 million, including up to initially: (1) $90.0 million under the letter of credit facility; and (2) $75.0 million under the swing line facility. Subject to customary conditions, MEP may request that the lenders’ aggregate commitments be increased to an amount not to exceed $1.0 billion. The facility matures in two years, subject to four one-year requests for extensions.

On September 30, 2014, MEP amended the MEP Credit Agreement to extend the maturity date from November 13, 2016, to September 30, 2017; however, $140.0 million of commitments will expire on the original maturity date of November 13, 2016.

At December 31, 2014, MEP had $360.0 million in outstanding borrowings under the MEP Credit Agreement at a weighted average interest rate of 3.2%. Under the MEP Credit Agreement, MEP had net

 

90


Table of Contents

repayments of approximately $25.0 million during the twelve month period ended December 31, 2014, which includes gross borrowings of $6,920.0 million and gross repayments of $6,895.0 million. At December 31, 2014, MEP was in compliance with the terms of their financial covenants under the MEP Credit Agreement.

EEP agreed to subordinate its right to payments from MEP under the Financial Support Agreement between us and MEP and liens, if secured, to the lenders under the MEP Credit Agreement. For further details regarding the MEP Credit Agreement and the amendments thereto, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt.

MEP Private Debt Issuance

On September 30, 2014, MEP completed a private offering of $400.0 million of debt securities pursuant to a Note Purchase Agreement, or the Purchase Agreement, between the Partnership and the purchasers named therein. The debt consists of three tranches of senior notes: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. The Notes and all other obligations under the Purchase Agreement are unconditionally guaranteed on a senior basis by each of the domestic material subsidiaries of the Partnership pursuant to a guaranty agreement. All of the Notes pay interest semi-annually on March 31 and September 30, commencing on March 31, 2015. MEP received approximately $398.1 million in net proceeds, which were used to repay outstanding indebtedness and for other general partnership purposes. Using a portion of the net proceeds, MEP settled two interest rate swaps for a net payment of $0.9 million on September 30, 2014, which will be amortized to interest expense over the original five year hedge term.

At December 31, 2014, MEP was in compliance with the terms of its financial covenants under the purchase agreement pursuant to which the Notes were sold. For further details related to the purchase agreement and the related private placement, refer to Item 8. Financial Statements and Supplementary Data, Note 10. Debt to the consolidated financial statements included in this Annual Report on Form 10-K.

Maturities of Third Party Debt

The scheduled maturities of outstanding third-party debt, excluding any discounts at December 31, 2014, are summarized as follows in millions:

 

2015

   $   

2016

     950.0  

2017

     360.0  

2018

     1,622.3  

2019

     575.0  

Thereafter

     3,175.0  
  

 

 

 

Total

   $ 6,682.3  
  

 

 

 

Joint Funding Arrangements

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

 

91


Table of Contents

Joint Funding Arrangement for Alberta Clipper Pipeline

In July 2009, we entered into a joint funding arrangement to finance construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge including our General Partner. On January 2, 2015, we completed a transaction pursuant to which the General Partner and its affiliates contributed to us a 66.7% interest in the U.S. segment of the Alberta Clipper Pipeline in exchange for approximately 18,114,975 units of our new class of limited partner interests designated as Class E units with an aggregate value of $694 million issued to the General Partner. In addition, we repaid approximately $306 million of indebtedness owed to the General Partner.

Joint Funding Arrangement for Eastern Access Projects

In May 2012, the OLP amended and restated its partnership agreement to establish the EA interests. The EA interests were created to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. From May 2012 through June 27, 2013, our General Partner indirectly owned 60% of all assets, liabilities and operations related to the Eastern Access Projects. On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding of the Eastern Access Projects from 40% to 25%. Additionally, within one year of the in-service date, scheduled for early 2016, we have the option to increase our economic interest by up to 15 percentage points. We received $90.2 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013, pursuant to Eastern Access Projects.

Our General Partner has made equity contributions totaling $622.5 million and $609.2 million to the OLP for the year ended December 31, 2014 and 2013, respectively to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Joint Funding Arrangement for the U.S. Mainline Expansion

In December 2012, the OLP further amended and restated its limited partnership agreement to establish another series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead System between Neche, North Dakota and Superior, Wisconsin, which we refer to as our Mainline Expansion Projects. From December 2012 through June 27, 2013, the projects were jointly funded by our General Partner at 60% and the Partnership at 40%, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement. On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding in the projects from 40% to 25%. We received $12.0 million from our General Partner in consideration for our economic interest. Additionally, within one year of the in-service date, currently scheduled for 2016, we have the option to increase our economic interest held at that time by up to 15 percentage points.

Our General Partner has made equity contributions totaling $577.5 million and $159.9 million to the OLP for the year ended December 31, 2014 and year ended 2013, respectively to fund its equity portion of the construction costs associated with the U.S. Mainline Expansion Projects.

Sale of Accounts Receivable

Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, as amended on September 20, 2013 and December 2, 2013, 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

 

92


Table of Contents

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 those of ours subsidiaries and other subsidiaries of EEP that are parties thereto up to an aggregate monthly maximum of $450.0 million net of receivables that have not been collected.

For the year ended December 31, 2014 we sold and derecognized receivables of approximately $4,987.0 million and we received cash proceeds of approximately $4,985.7 million which was remitted to us through our centralized treasury system. As of December 31, 2014, $378.0 million, of the receivables were outstanding and had not been collected on behalf of the Enbridge subsidiary.

As of December 31, 2014, we had $71.9 million included in “Restricted cash” on our consolidated statements of financial position, consisting of cash collections related to the Receivables sold that have yet to be remitted to the Enbridge subsidiary as of December 31, 2014. For further discussion, refer to Note 12. Related Party Transactions in the consolidated financial statements of this Annual Report on Form 10-K.

Cash Requirements

Capital Spending

We expect to make additional expenditures during 2015 for the acquisition and construction of natural gas processing and crude oil transportation infrastructure. In 2015, we expect to spend approximately $1.3 billion on expansion capital and other projects associated with our liquids and natural gas systems with the expectation of realizing additional cash flows as projects are completed and placed into service. We expect to receive funding of approximately $1.1 billion from our General Partner based on our joint funding arrangement for the Eastern Access Projects, Mainline Expansion Projects and Line 3 Replacement project. Furthermore, we expect to receive funding of approximately $185.0 million from MPC based on joint funding arrangement on the Sandpiper Project. We made expenditures of $2.8 billion for the year ended December 31, 2014, inclusive of capital leases entered into during the year, $36.7 million in contributions to the Texas Express Pipeline and $1,391.6 million of expenditures that were financed by contributions from our General Partner and MPC via joint funding arrangements. At December 31, 2014, we had approximately $946.8 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment during 2014.

Acquisitions

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

Forecasted Expenditures

We categorize our capital expenditures as either maintenance capital or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which are worn, obsolete or completing its useful life. We also include in maintenance capital expenditures a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems. 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.

 

93


Table of Contents

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. The following table sets forth our estimates of capital expenditures we expect to make for expansion capital and maintenance capital for the year ending December 31, 2015. Although we anticipate making these expenditures in 2015, 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. We made capital expenditures of $2.8 billion, including $129.8 million on maintenance capital activities, for the year ended December 31, 2014. For the full year ending December 31, 2015, we anticipate our capital expenditures to approximate the following:

 

      Total
Forecasted
Expenditures
 
     (in millions)  

Liquids Projects

  

Eastern Access Projects

   $ 405  

U.S. Mainline Expansions

     1,075  

Sandpiper

     490  

Line 3 Replacement

     60  

Liquids Integrity Program

     225  

Expansion Capital

     155  

Maintenance Capital Expenditures

     75  
  

 

 

 
     2,485  

Less joint funding from:

  

General Partner

     1,140  

Third parties

     185  
  

 

 

 

Liquids Total

     1,160  

Natural Gas Projects

  

Beckville Cryogenic Processing Plant

   $ 50  

Eaglebine Developments

     135  

Expansion Capital

     105  

Maintenance Capital Expenditures

     55   
  

 

 

 
     345  

Less joint funding from:

  

MEP

     180  
  

 

 

 

Natural Gas Total

     165  
  

 

 

 

TOTAL

   $     1,325  
  

 

 

 

We maintain a comprehensive integrity management program for our pipeline systems, which relies on the latest technologies that include internal pipeline inspection tools. These internal pipeline inspection tools identify internal and external corrosion, dents, cracking, stress corrosion cracking and combinations of these conditions. We regularly assess the integrity of our pipelines utilizing the latest generations of metal loss, caliper and crack detection internal pipeline inspection tools. We also conduct hydrostatic testing to determine the integrity of our pipeline systems. Accordingly, we incur substantial expenditures each year for our integrity management programs.

Under our capitalization policy, expenditures that replace major components of property or extend the useful lives of existing assets are capital in nature, while expenditures to inspect and test our pipelines are usually considered operating expenses. The capital spending components of our programs have increased over time as our pipeline systems age.

 

94


Table of Contents

We expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Expenditure levels have continued to increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital will continue to increase due to the growth of our pipeline systems and the aging of portions of these systems. Maintenance capital expenditures are expected to be funded by operating cash flows.

We anticipate funding expansion capital expenditures temporarily through borrowing under the terms of our Credit Facility, with permanent debt and equity funding being obtained when appropriate.

Environmental

Lakehead Line 6B Crude Oil Release

During 2014, our cash flows were affected by the approximate $141.4 million we paid for environmental remediation, restoration and cleanup activities resulting from the crude oil release that occurred in 2010 on Line 6B of our Lakehead system.

In March 2013, we and Enbridge filed a lawsuit against the insurers of our remaining $145.0 million coverage, as one particular insurer is disputing our recovery eligibility for costs related to our claim on the Line 6B crude oil release and the other remaining insurers assert that their payment is predicated on the outcome of our recovery with that insurer. We received a partial recovery payment of $42.0 million from the other remaining insurers during the third quarter 2013 and have since amended our lawsuit, such that it now includes only one carrier. While we believe that our claims for the remaining $103.0 million are covered under the policy, there can be no assurance that we will prevail in this lawsuit.

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 interest rates and 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 interest rates or commodity prices.

 

95


Table of Contents

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, 2014 for each of the indicated calendar years:

 

    Notional     2015     2016     2017     2018     2019     Total(3)(4)  
    (in millions)  

Swaps

             

Natural gas(1)

    85,892,590     $ 2.8     $ 0.1     $     $     $      $ 2.9   

NGL(2)

    3,395,200       32.4       9.3       0.7                   42.4   

Crude Oil(2)

    3,868,565       37.6       1.0       0.8                   39.4   

Options

             

Natural gas—puts purchased(1)

    5,662,000       3.8       1.0                         4.8   

Natural gas—calls written(1)

    2,924,500              (0.1                         (0.1 )  

NGL—puts purchased(2)

    5,456,000       40.2       39.3       1.2                    80.7   

NGL—calls written(2)

    4,634,750       (0.6     (3.2     (0.7