10-K 1 d665022d10k.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, 2013

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, or the average bid and asked price of such common equity, as of June 30, 2013, was $6,330,149,823.

As of February 14, 2014 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      38   

Item 2.

  Properties      57   

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      121   

Item 8.

  Financial Statements and Supplementary Data      133   

Item 9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      214   

Item 9A.

  Controls and Procedures      214   

Item 9B.

  Other Information      215   
  PART III   

Item 10.

  Directors, Executive Officers and Corporate Governance      216   

Item 11.

  Executive Compensation      223   

Item 12.

  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      250   

Item 13.

  Certain Relationships and Related Transactions, and Director Independence      252   

Item 14.

  Principal Accountant Fees and Services      264   
  PART IV   

Item 15.

  Exhibits and Financial Statement Schedules      264   

Signatures

     266   

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; and (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.

For additional factors that may affect results, see “Item 1A. Risk Factors” included elsewhere in this Annual Report on Form 10-K and our subsequently filed Quarterly Reports on Form 10-Q, which are 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).

 

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Glossary

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

 

AEDC

   Allowance for equity during construction

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

Amended EDA

   Amended and Restated Equity Distribution Agreement

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)

Bpd

   Barrels per day

CAA

   Clean Air Act

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

CAD

   Amount denominated in Canadian dollars

CWA

   Clean Water Act

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.

EDA

   Equity Distribution Agreement

EES

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

Elk City system

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

Enbridge

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

Enbridge Management

   Enbridge Energy Management, L.L.C.

Enbridge system

   Canadian portion of the liquid petroleum mainline system

Enbridge Pipelines

   Enbridge Pipelines Inc.

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

FSM

   Facilities Surcharge Mechanism

General Partner

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

ICA

   Interstate Commerce Act

ISDA®

   International Swaps and Derivatives Association, Inc.

Lakehead system

   United States portion of the liquid petroleum mainline system

 

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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

MDNRE

   Michigan Department of Natural Resources and Environment

ME interests

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

MEP

   Midcoast Energy Partners, L.P.

Midcoast Operating

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

MLP

   Master Limited Partnership

MMBtu/d

   Million British Thermal units per day

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

NEB

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

NGA

   Natural Gas Act

NGL or NGLs

   Natural gas liquids

NGPA

   Natural Gas Policy Act

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

NYMEX

   The New York Mercantile Exchange where natural gas futures, options contracts and other energy futures are traded

NYSE

   New York Stock Exchange

OLP

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

OPA

   Oil Pollution Act

PADD

   Petroleum Administration for Defense Districts

PADD I

   Consists of Connecticut, Delaware, District of Columbia, Florida, Georgia, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia and West Virginia

PADD II

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

 

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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

   Fourth Amended and Restated Agreement of Limited Partnership of Enbridge Energy Partners, L.P.

Partnership

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

Phase 5 & 6

   Expansion Programs on our North Dakota system

PHMSA

   Pipeline and Hazardous Materials Safety Administration

PIPES of 2006

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

PPI-FG

   Producer Price Index for Finished Goods

PSA

   Pipeline Safety Act

SAGD

   Steam assisted gravity drainage

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

Southern Access

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

Suncor

   Suncor Energy Inc., an unrelated energy company

Syncrude

   Syncrude Canada Ltd., an unrelated energy company

Synthetic crude oil

   Product that results from upgrading or blending bitumen into a crude oil stream, which can be readily refined by most conventional refineries

Tariff Agreement

   A 1998 offer of settlement filed with the FERC

Terrace Surcharge

   Terrace expansion program, an expansion program on our Lakehead system

TSX

   Toronto Stock Exchange

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

WCSB

   Western Canadian Sedimentary Basin

 

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PART I

Item 1.    Business

OVERVIEW

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.” 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, 2013. The ownership percentages referred to below illustrate the relationships between us, Enbridge Energy Management, L.L.C., referred to as Enbridge Management, our General Partner and Enbridge and its affiliates:

 

LOGO

 

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We were formed in 1991 by our General Partner, 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, 2013, our portfolio of assets included the following:

 

   

Approximately 6,350 miles of crude oil gathering and transportation lines and 34 million barrels, or MMBbl, of crude oil storage and terminaling capacity;

 

   

Approximately 11,600 miles of natural gas gathering and transportation lines and approximately 226 miles of NGL gathering and transportation lines;

 

   

A 35% interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together own a 580-mile, 20-inch NGL intrastate transportation pipeline extending from the Texas Panhandle to Mont Belvieu, Texas and a related NGL gathering system that consists of approximately 116 miles of gathering lines;

 

   

21 active natural gas processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants, with a combined capacity of approximately 2.0 billion cubic feet per day, or Bcf/d, including 350 million cubic feet per day, or MMcf/d, provided by our HCDP plants;

 

   

Eight active natural gas treating plants, including three that are leased from third parties, with a total combined capacity of approximately 1.1 Bcf/ds;

 

   

Approximately 570 compressors with approximately 816,000 aggregate horsepower, the substantial majority of which are owned by Midcoast Operating and the remainder of which are leased from third parties;

 

   

A liquids railcar loading facility near Pampa, Texas, which we refer to as our TexPan liquids railcar facility;

 

   

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

 

   

Approximately 250 transport trucks, 300 trailers and 205 railcars for transporting NGLs; and

 

   

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 a special class of our limited partner interests, which we refer to as i-units.

 

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BUSINESS STRATEGY

Our primary objective is to provide stable 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.

 

  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.

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

 

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Liquids

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

 

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 2013, 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 2013 from the United States Department of Energy’s Energy Information Administration, or EIA, Canada supplied approximately 2.5 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 (CAPP), in their June 2013 forecast of future production from the Alberta oil sands, continued to expect steady growth in supply during the next two decades with an additional 4.2 million Bpd of incremental supply available for transportation 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

 

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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.

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 production to key refinery markets in the United States. 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 North America’s first choice for liquids deliveries.

Since last year, we and Enbridge have announced multiple upstream and downstream new build and expansion projects that 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, as discussed below, complements our already announced Eastern Access and Light Oil Market Access initiatives.

Eastern Access

Our joint Eastern Access initiative is comprised of expansion projects that provide both heavy & light producers with increased market access to the eastern Midwest and eastern Canadian refining markets. We have entered into a joint funding agreement with Enbridge for the expansion of Line 5 and Spearhead North (or Line 62) while also replacing Line 6B. Completed earlier in 2013, the Line 5 expansion project has increased the line’s capacity between Superior, Wisconsin and Sarnia, Ontario by 50,000 Bpd. Additionally, ours and Enbridge’s Line 6B replacement project will replace 210 miles of existing pipeline and add 260,000 bpd day of capacity into the Sarnia refining center. The in-service date for the Line 6B replacement project is Q1 2014 for the Griffith, Indiana to Stockbridge, Michigan segment and Q3 2014 for the segment from Ortonville, Michigan to Sarnia, Ontario. Additionally, the joint funded Line 62) expansion has brought an additional 105,000 bpd of capacity from our Flanagan terminal into our Griffith terminal in November 2013.

To complement these jointly funded expansions, Enbridge also announced plans to increase connectivity to the Toledo and eastern Canadian refining markets, both relying on our Lakehead system for additional volumes. Enbridge has already received regulatory approvals to reverse Line 9A and has undergone a regulatory process for reversing Line 9B. Enbridge’s Line 9A reversal was completed in 2013, adding 240,000 bpd of east-flowing capacity into Enbridge’s Westover, Ontario terminal. Subject to Enbridge receiving a favorable regulatory decision, Line 9B could go into service in the latter half of 2014 providing 300,000 bpd of pipeline capacity to the Montreal refining market. The Enbridge-funded Toledo Pipeline Twin will add 80,000 bpd of new capacity into the Toledo refining market. Both Enbridge-funded market access projects will access volumes from our Lakehead system.

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 barrels of oil to Clearbrook, Minnesota and 375,000 barrels a day to our Superior terminal located in north western Wisconsin. The Sandpiper pipeline is a key pipeline that will supply numerous Enbridge and Partnership funded downstream pipeline expansions and new builds. We, along with Enbridge, will twin Line 62 which will add 570,000 bpd of new pipeline capacity into Enbridge’s Hartsdale terminal by Q3 2015. Then we, along with Enbridge, will expand the replaced Line 6B to 570,000 in early 2016. The Enbridge-funded Southern Access Extension and Line 9 reversal and 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, IL to Patoka, IL will add 300,000 bpd into the Patoka terminal in 2015.

 

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In North Dakota, oil production levels rose to approximately 932,000 bpd during September 2013 which is an approximate 21% increase since the month of December 2012. Capitalizing on this growth, we continue to develop complementary rail options to access key refinery markets for the Bakken region as pipelines develop. Our Berthold Rail Project will allow 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.

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

 

   

Enbridge’s Flanagan South Pipeline, a twinning of its existing Spearhead system, will transport higher volumes from Flanagan, Illinois into the Cushing hub. The 36-inch diameter pipeline will have an initial capacity of approximately 585,000 Bpd, and subject to regulatory and other approvals, the pipeline is expected to be in service by mid-2014.

 

   

Seaway Crude Pipeline System—In 2011, Enbridge completed the acquisition of a 50% interest in the Seaway Crude Pipeline System, or Seaway. Seaway was a 670-mile pipeline that includes a 500-mile, 30-inch pipeline long-haul system from Freeport, Texas to Cushing, Oklahoma, as well as a Texas City Terminal and Distribution System that serves refineries in Houston and Texas City areas. In March 2012, the direction of the 500-mile Seaway pipeline was reversed to enable it to transport oil from Cushing, Oklahoma to the United States Gulf Coast, providing capacity of 150,000 bpd. Further pump station additions and modifications, which were completed in January 2013, increased capacity up to 400,000 bpd, depending upon the mix of light and heavy grades of crude oil. Enbridge together with Enterprise is also twinning the existing Seaway pipeline which will add 450,000 bpd of capacity to the system by mid-2014. In addition, in March 2012, plans were announced to construct an 85-mile pipeline from Enterprise Product’s ECHO crude oil terminal southeast of Houston to the Port Arthur/Beaumont, Texas refining center. When completed, this is expected to provide 750,000 Bpd of capacity by mid-2014.

 

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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 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 61% 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

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

 

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natural gas markets and natural gas liquids, or 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 three business segments:

 

   

Liquids;

 

   

Natural Gas; and

 

   

Marketing.

These segments have unique business activities that require different operating strategies. For information relating to revenues from external customers, operating income and total assets for each segment, refer to Note 18. Segment Information of our consolidated financial statements beginning on page 204 of this report.

Liquids Segment

Lakehead system

Our Lakehead system consists primarily of crude oil and liquid petroleum common carrier pipelines and terminal assets in the Great Lakes and Midwest regions of the United States. The 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 serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the province of Ontario, Canada.

Over the past five years, we have completed the largest pipeline expansion program in our history. During the 2008 through 2010 time periods, 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

 

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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. The Southern Access Pipeline can be expanded further to a total capacity of 1.2 million Bpd with additional pumping station capital. The United States portion of the Alberta Clipper Pipeline can also be further expanded to 800,000 Bpd. Supply from the Bakken play in North Dakota is expected to reach over 800,000 Bpd by 2015 and over 1 million Bpd by 2021. Western Canada oil sands production is expected to grow by 3.3 million Bpd to over 5 million Bpd by 2030. With this production growth, the industry requires more capacity to transport crude oil out of North Dakota and the oil sands regions into the United States Midwest markets and interconnecting transportation hubs. The need for further capacity on our Lakehead system was driven by producers and refiners that 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. Both the Alberta Clipper and Southern Access Pipelines were a direct response to this need.

Our Lakehead system is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission, or FERC. Our Lakehead system spans a distance of approximately 2,200 miles and consists of approximately 5,100 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 system has 64 pump station locations with a total of approximately 920,000 installed horsepower and 72 crude oil storage tanks with an aggregate capacity of approximately 14 million barrels. The Mainline system, as a whole, operates in a segregation, or batch mode, allowing the transport of 48 crude oil commodities including light, medium and heavy crude oil (including bitumen, which is a naturally occurring tar-like mixture of hydrocarbons), condensate and NGLs.

Customers.    Our Lakehead system operates under month-to-month transportation arrangements with our shippers. During 2013, approximately 47 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 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. The National Energy Board, or NEB, estimated that total production from the WCSB averaged approximately 3.3 million Bpd in 2013 and 3 million in 2012. Meanwhile, strong production growth from the Bakken formation has increased tight oil available from North Dakota to nearly 780,000 Bpd in 2013, as compared to 600,000 Bpd in 2012. With access to growing supply from the WCSB and Bakken formation, the Lakehead system will remain an important conduit for crude oil to U.S. markets for years to come. Volumes of WCSB crude oil production exceed those from Iraq and Venezuela, key members of the Organization of Petroleum Exporting Countries, or OPEC.

Remaining established reserves from the Alberta Oil Sands as of the end of 2012 were approximately 168 billion barrels according to the Alberta Energy Regulator, or AER. Additionally, remaining established conventional oil reserves in Western Canada were estimated to be approximately 3.4 billion barrels at the end of 2012. Canada’s total combined conventional and oil sands estimated proved reserves of approximately 174 billion barrels at the end of 2012 compares with Saudi Arabia’s estimated proved reserves of approximately 266 billion barrels.

According to CAPP, an estimated total $359 billion Canadian dollars, or CAD, has been spent on oil sands development from 1997 through 2012. The rate of growth of the Alberta Oil Sands moderated in previous years due to declining demand and commodity prices; however, rising oil prices and demand has led to a rebound in production growth and the announcement of new oil sands projects, as noted in the discussion below. As mentioned above, CAPP’s June 2013 Growth Forecast estimates that the future production from the Alberta Oil

 

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Sands is expected to grow steadily during the next 17 years, with an additional 3.3 million Bpd of incremental production available by 2030.

The near-term growth in crude oil supply comes from the completion and ramp up of major expansion projects at existing synthetic crude oil upgraders and growth of bitumen production from both existing and new Steam Assisted Gravity Drainage, or SAGD, and mining facilities. The 2013 delivered production of four major Alberta Oil Sands producers is detailed as follows:

 

   

Suncor’s oil sands production grew to 361,000 Bpd in 2013, up from 324,000 Bpd in 2012 (includes upgraded sweet and sour synthetic crude oil as well as non-upgraded bitumen). Suncor completed Stage 4 expansion at its Firebag project at the end of 2012 and is expecting production from the project to reach 180,000 Bpd in early 2014. Moving forward, the company will continue to focus on developing existing projects such as Mackay River and Firebag as well as other potential in situ growth prospects. Also, as disclosed in a news release during 2013, Suncor has decided to proceed with the Fort Hills oil sands project, which is expected to increase bitumen production by 180,000 Bpd by 2017;

 

   

Syncrude Canada Ltd.’s, or Syncrude’s, synthetic production in 2013 averaged 267,000 Bpd, which is slightly below production levels from 2012. Syncrude operates five mine trains on its active leases, four of which will be replaced or relocated by the end of 2014 to sustain and improve bitumen production. Plans are in place to coordinate these efforts such that production should not be affected. Syncrude’s next expansion is the Stage 3 debottleneck which would increase their current system’s synthetic production by approximately 75,000 Bpd. The projected in-service date of the Stage 3 debottleneck has not been established;

 

   

In June 2013, Cenovus began production at Phase E of its Christina Lake Project. Phase E is expected to yield an additional 40,000 Bpd of production and brings the project’s production capacity up to 138,800 Bpd at the end of 2013. Construction of Phase F is on schedule for a 2016 startup and preliminary work is underway for subsequent project phases in the coming years. With continued optimizations and expansions, the ultimate capacity of the Christina Lake project is approximately 310,000 Bpd; and

 

   

In Imperial Oil’s Kearl oil sands project began operating in April 2013. Initial production will ramp up to approximately 110,000 Bpd unblended by 2015. The project has regulatory approval for up to 345,000 Bpd of production with its additional phases and will be one of Canada’s largest oil sands mining operations. Production will be sold as blended bitumen and shipped upstream via Enbridge’s Woodland Pipeline.

Over the next two years, a number of individual projects are expected to come on-line that should start to increase the production of unblended bitumen. Other notable projects include Husky’s Sunrise, Athabasca Oil Corporation’s Hangingstone, ConocoPhillips’ Surmont and MEG Energy’s Christina Lake. Based on the CAPP Production forecast, unblended bitumen production is expected to increase by roughly 177,000 Bpd by the end of 2014 and then increase by an additional 124,000 Bpd by the end of 2015.

Although the crude oil and liquid petroleum delivered through our Lakehead system originates primarily in oilfields in Western Canada, our Lakehead system also receives a portion of its receipts from domestic sources including:

 

   

United States Bakken production at Clearbrook, Minnesota through a connection with our North Dakota system;

 

   

United States production at Lewiston, Michigan; and

 

   

Both United States and offshore production in the Chicago area.

 

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In the coming years, Bakken production is expected to become a major component of the United States domestic supply mix. Estimates from the United States Energy Information Administration expect production to reach 800,000 Bpd by 2015 and over 1 million Bpd by 2021. Other industry experts have production forecasts which are higher.

Based on forecasted growth in Western Canadian crude oil production and completion of upgrader expansions and increased bitumen production, our Lakehead system deliveries are expected to grow beyond the 1.8 million Bpd of actual deliveries in 2013. 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, United States demand and 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 affected by periodic maintenance, refinery turnarounds and other shutdowns at producing plants that supply crude oil to, or refineries that take delivery from, our Lakehead system.

Refinery configurations and crude oil requirements in the Petroleum Administration for Defense District II, or PADD II, continue to create an attractive market for Western Canadian supply. According to the EIA, 2013 demand for crude oil in PADD II averaged 3.4 million Bpd, a decrease of 68,000 Bpd from 2012. At the same time, production of crude oil within PADD II increased by 244,000 Bpd to 1.4 million Bpd. A significant contributor to the decrease in demand for crude oil in PADD II is a result of BP’s Whiting, Indiana refinery undergoing a major upgrade throughout 2013. The project faced delays throughout 2013 but will begin to ramp up production in the first quarter of 2014. The 405,000 Bpd refinery is the largest refinery in the United Stated Midwest. Other Midwest refineries also experienced significant turnarounds during 2013, which contributed to decreases in demand.

Competition.    Our Lakehead system, along with the Enbridge system, is the main crude oil export route from the WCSB and a key transportation component for growing Bakken production. WCSB production in excess of Western Canadian demand moves on existing pipelines into PADD II, the Rocky Mountain states (PADD IV), the Anacortes area of Washington state (PADD V), the United States Gulf Coast (PADD III) and to Eastern Canada (Ontario). In each of these regions, WCSB crude oil competes with local and imported crude oil. As local crude oil production declines and refineries demand more imported crude oil, imports from the WCSB should increase.

For 2013, the latest data available shows that PADD II total demand was 3.4 million Bpd while it produced only 1.4 million Bpd and thus imported 2 million Bpd from Canada and other regions of the United States. The 2013 data indicates PADD II imported approximately 1.8 million Bpd of crude oil from Canada, a majority of which was transported on our Lakehead system. The remaining barrels were imported via competitor pipelines from Alberta, and from PADDs III and IV as well as from offshore sources via the United States Gulf Coast. Lakehead system deliveries for 2013 were approximately 24,000 Bpd higher than delivery volumes for 2012. Total deliveries from our Lakehead system averaged 1.8 million Bpd in 2013, meeting approximately 84% of the refinery capacity in the greater Chicago area; 85% of the Minnesota refinery capacity; and 81% of Ontario refinery capacity in 2013.

Considering all of the transportation systems that transport crude oil out of Canada, the Mainline system transported approximately half of all Canadian crude oil imports to the United States in 2013. The Lakehead system mainly serves PADD II market directly and PADD III indirectly. The remaining import volume was transported by systems serving PADD II, PADD IV and PADD V 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. These proposals and projects

 

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range from expansions of existing pipelines that currently transport Western Canadian crude oil, to new pipelines and extensions of existing pipelines. Transportation of oil by rail is also a competitive alternative to certain markets. These proposals and projects are in various stages of development, with some at the concept stage and others that are operational. Some of these proposals are in direct competition with our Lakehead system.

Enbridge has filed an application with the NEB for construction of the Northern Gateway Pipeline, which includes both a condensate import pipeline and a petroleum export pipeline. The condensate line would transport imported diluent from Kitimat, British Columbia to the Edmonton, Alberta area. The petroleum export line would transport crude oil from the Edmonton area to Kitimat and would compete with our Lakehead system for production from the Alberta Oil Sands. On December 19, 2013, the National Energy Board’s Joint Review Panel released a recommendation to the Canadian Federal Government to approve the project, subject to certain conditions. The Federal Government will render its final decision by July 2014. Given the substantial growth in Western Canadian crude oil supply, this pipeline will provide another market option for Canadian crude oil, an important consideration for Canadian crude oil producers.

We and Enbridge believe that the Southern Access Pipeline, Alberta Clipper Pipeline, the Line 5 expansion, Flanagan South pipeline, the Seaway reversal, Eastern Access Projects, Light Oil Market Access Program and other initiatives to provide access to new markets in the Midwest, Mid-Continent, Eastern Canada and Gulf Coast, offer flexible solutions to future transportation requirements of Western Canadian crude oil producers.

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 and extend down to Cushing and then to Nederland, Texas. The pipeline will connect to existing crude oil pipeline from Hardisty, Alberta to Wood River, Illinois and Patoka. Construction of the pipeline will add an additional 700,000 Bpd of capacity when completed. However, in early 2012, the United States 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 National Energy Board 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 barrels per day 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 2017.

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. They could also affect throughput on and utilization of the Mainline system. However, together, the Lakehead and Enbridge systems offer significant cost savings and flexibility advantages, which are expected to continue to favor the Mainline

 

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system as the preferred alternative for meeting shipper transportation requirements to the Midwest United States and beyond.

 

     2013      2012      2011      2010      2009  
     (thousands of Bpd)  

United States

              

Light crude oil

     473        521        473        458        467  

Medium and heavy crude oil

     948        879        850        841        834  

NGL

     6        5        4        3        4  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total United States

     1,427        1,405        1,327        1,302        1,305  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Ontario

              

Light crude oil

     247        228        220        223        197  

Medium and heavy crude oil

     76        85        84        57        73  

NGL

     66        72        69        73        75  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Ontario

     389        385        373        353        345  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Deliveries

     1,816        1,790        1,700        1,655        1,650  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Barrel miles (billions per year)

     487        480        450        439        423  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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; Flanagan, Illinois; and El Dorado, Kansas. Our Mid-Continent system includes over 435 miles of crude oil pipelines and 20.9 million barrels of crude oil storage capacity. This excludes 1.2 million barrels of crude oil storage related to the disposition of the El Dorado storage facility in November 2013. Our Ozark pipeline transports crude oil from Cushing to Wood River, where it delivers to ConocoPhillips’ Wood River refinery and interconnects with the Woodpat Pipeline and the Wood River Pipeline, each owned by unrelated parties.

The storage terminals consist of 95 individual storage tanks ranging in size from 55,000 to 575,000 barrels. In 2013, 936,000 barrels of incremental shell capacity came into service. Of the 20.9 million barrels of storage shell capacity on our Mid-Continent system, the Cushing terminal accounts for 19.9 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.

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 2013, approximately 62 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 202,000 Bpd for 2013 and 223,000 Bpd for 2012.

Supply and Demand.    Our Mid-Continent system is positioned to capitalize on increasing near-term demand for crude oil from west Texas and imported crude oil delivered to the United States Gulf Coast, as well as third-party storage demand. In addition, our system is also positioned to capitalize on increasing Canadian imports into the United States. In 2013, PADD II imported 2 million Bpd from outside of the PADD II region. The 2013 data indicates PADD II imported approximately 1.8 million Bpd of crude oil from Canada, a majority

 

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of which was transported 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 and Wood River. 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 new pipeline from Hardisty to Patoka 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 expected to be transported on the new 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, crude oil in Cushing is transported to Chicago and El Dorado on third-party pipeline systems. Western Canadian crude oil moving on Spearhead to Cushing 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 include large integrated oil companies and other midstream energy partnerships. Demand for storage capacity at Cushing has remained steady 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 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 820 miles long, has 23 pump stations, multiple delivery points and storage facilities with an aggregate working storage capacity of approximately 1.3 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 more than a dozen third party gathering pipeline connections, and deliver a fungible common stream to a variety of interconnecting pipeline and rail export facilities.

Traditionally, the majority of our pipeline deliveries have been made into interconnecting pipelines at Clearbrook, Minnesota where two other pipelines originate: a third-party pipeline serving Northern Tier refinery markets and our Lakehead system providing further pipeline transportation on the Enbridge system into the Great Lakes, eastern Canada and US 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 pipeline and rail export capacity of more than 435,000 bpd in 2013 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

 

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approximately 200,000 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, and we will receive 100% of these commitments beginning March of 2014. 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 (“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 300,000 bpd from third party pipelines and more than 500,000 bpd from Enbridge truck and gathering facilities.

 

   

Berthold Rail Project—In December 2011, we announced Enbridge’s first crude oil unit-train rail export facility known as the Berthold Rail Project. With NDPSC approvals received in May 2012 and an initial 10,000 bpd truck-to-rail Phase 1 replaced by the full scale pipe-to-rail operation of 80,000 bpd placed into service in March 2013, Berthold Rail provided our North Dakota customers with an alternative transportation solution to shipper needs in the Bakken region. Today, Berthold Rail feeds Bakken crude to US West Coast, US Gulf Coast and US East Coast markets and provides an excellent complement to the options and market access available to Enbridge customers.

 

   

Berthold West—In October 2013, Enbridge Storage (North Dakota) placed the first of two 150,000 contract storage tanks into service during 2013 at its new merchant storage facility located adjacent to Berthold Station and the Berthold Rail Project. At Berthold, ESND has an ultimate capacity of 450,000 barrels of total storage capacity, and with similar properties located adjacent to our various facilities across North Dakota, has the opportunity to expand this new line of business to other locations across the Bakken region.

 

   

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 (“NDPL”). 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 Clearbrook, Minnesota will be a 225,000 bpd 24” pipeline and the portion from Clearbrook to Superior will be a 30” pipeline with 375,000 bpd of capacity.

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.

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

 

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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 932,000 Bpd as of September 2013 with projections of exceeding 1 Million Bpd in early 2014. The latest data released in August 2012 by the EIA shows that proved reserves of crude oil in North Dakota were approximately 1.8 billion barrels, a 73% increase from the EIA 2010 Summary. Significant advancements in exploration techniques and an increased understanding of the Williston Basin now suggest the proved reserve base to be substantially higher than what the EIA published.

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 75% of the total Bakken crude exported from North Dakota. Rail provides some advantages to pipeline transportation alternatives, but its recent dominance in market share is considered to be primarily driven by extreme price differentials Bakken crudes received vis-à-vis Brent or other non-Cushing based oil markets. Future Enbridge pipeline expansions and enhanced market access to eastern Canadian markets and eastern PADD II are expected to decrease current crude oil price differentials. As pipeline expansion projects create more export capacity from the Bakken, other pipeline projects provide increased access to more refinery markets across the United States, and price differentials return to long term average levels, more North Dakota customers are expected to shift their volumes back to pipelines as the primary transportation option given the economies of scale and other advantages that pipeline transportation enjoy vis-à-vis rail.

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 61% 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 58 miles of NGL pipelines, nine active natural gas processing plants, three standby natural gas processing plants and one standby treating plant located in the Anadarko basin.

 

   

East Texas system: Approximately 3,900 miles of natural gas gathering and transportation pipelines, approximately 108 miles of NGL pipelines, six active natural gas processing plants, including two

 

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

 

   

North Texas system: Approximately 4,600 miles of natural gas gathering and transportation pipelines, approximately 60 miles of NGL pipelines, six active natural gas processing plants and one standby natural gas processing plant located in the Fort Worth basin.

 

   

Texas Express NGL system: A 35% interest in an approximately 580-mile NGL intrastate transportation mainline and a related NGL gathering system that consists of approximately 116 miles of gathering lines.

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

Supply and Demand.    Demand for our gathering, processing and transportation services primarily depends upon the supply of natural gas reserves and 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 and the prices of natural gas and NGLs. During 2013, NGL prices were at levels higher than prices experienced in the prior year, while natural gas prices were only slightly higher than the prior year. Condensate pricing remained strong and is more closely associated with movements in domestic crude oil prices. As a result of the combination of these pricing dynamics, drilling activity has increased in areas known to have natural gas with high levels of NGL content, such as the Granite Wash play and the Barnett Shale. Additionally, supply in both of these areas has benefited from enhanced horizontal drilling and fracturing techniques, enabling higher flow rates from the wells of the producers. As drilling rates improve, and the number of drilling rigs increase, we would expect the demand for our services to increase. Our existing systems are located in basins that have the opportunity to grow in an improved pricing environment. All of our gathering, processing and transportation systems exist in regions that have shale or tight sands formations where horizontal fracturing technology can be utilized to increase production from the natural gas wells.

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. Favorable pricing for NGLs relative to natural gas has encouraged producers to increase production in the Granite Wash play due to the high NGL and condensate content. Our Anadarko basin wells generally have long lives with predictable flow rates. Producers are pursuing wells with higher condensate and oil production relative to historical activity that was focused on lower-valued gas 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, current market prices for NGLs and crude oil and the application of horizontal drilling and fracturing technology to the formation. In order to accommodate the expected growth of the Granite Wash play, we 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 million. The Ajax processing plant increases the total processing capacity of our Anadarko system by approximately 150 million cubic feet per day, or MMcf/d, to approximately 1,150 MMcf/d and also increases the system’s condensate stabilization capacity by approximately 2,000 Bpd. The Ajax

 

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processing plant is capable of producing approximately 15,000 barrels per day, or Bpd, of NGLs now that the Texas Express NGL pipeline, which we refer to as the mainline, was completed and put into operation during the fourth quarter of 2013.

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 marketing business. A portion of our owned NGLs is sold directly to OneOk Partners, L.P. (“ONEOK”), while the remainder is sold to our marketing business. The NGLs produced at our Anadarko system processing plants are transported by pipeline to third party fractionation facilities and NGL market hubs in Conway, Kansas and Mont Belvieu, Texas.

East Texas System

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

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 is expected to serve existing and prospective customers pursuing production in the Cotton Valley formation. 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 million and expect it to commence service in early 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 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 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 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. Our North Texas wells are located in the Fort Worth basin and generally have long lives 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.

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

 

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connect our facilities to market centers in the Dallas-Fort Worth area and ultimately to major market hubs in the U.S. Gulf Coast. The majority of our owned residue gas and all of our owned condensate and NGLs produced at our North Texas system processing plants is sold to our marketing business.

Texas Express NGL System

Volumes from the Rockies, Permian basin and Mid-Continent regions will be delivered to the Texas Express NGL system utilizing Enterprise Products Partners’ existing Mid-America Pipeline between the Conway hub and Enterprise Products Partners’ Hobbs NGL fractionation facility in West Texas. In addition, volumes from and to the Denver-Julesburg basin in Weld County, Colorado will be able to access the system upon the completion of the Front Range Pipeline by Enterprise Products Partners, DCP Midstream and Anadarko Petroleum Corporation, which could occur as early as the first quarter of 2014.

The Texas Express NGL system commenced startup operations during the fourth quarter of 2013. During startup operations, revenue recognition is delayed while the system is being filled with NGLs but operating costs are recognized. Additionally, the Texas Express NGL system operates using ship or pay contracts. These ship or pay contracts contain make-up rights provisions, which are earned when minimum volume commitments are not utilized during the contract period but are also subject to contractual expiry periods. Revenue associated with these make-up rights is deferred when more than a remote chance of future utilization exists. These factors in combination contributed to lower equity earnings.

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 NGL Marketing Operations

We also include our trucking and NGL marketing operations in our Natural Gas segment. The primary role of our trucking and NGL marketing business is to provide our customers with the opportunity to receive enhanced economics by providing access to premium markets through the transportation capacity and other assets we control. Our trucking and NGL marketing business purchases and receives natural gas, NGLs and other products from pipeline systems and processing plants and sells and delivers them to wholesale customers, such as distributors, refiners, fractionators, utilities, chemical facilities and power plants.

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

 

   

Approximately 250 transport trucks, 300 trailers and 205 railcars for transporting NGLs;

 

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Our TexPan liquids railcar facility near Pampa, Texas; and

 

   

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

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

 

   

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

 

   

approximately 2.5 Bcf of firm natural gas storage capacity;

 

   

up to approximately 120,000 Bpd of firm NGL transportation capacity on the Texas Express NGL system;

 

   

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

 

   

approximately 5.0 MMBbls of firm NGL storage capacity.

NGL Marketers.    Most of the customers of our trucking and NGL marketing operations are wholesale customers, such as refiners and petrochemical producers, fractionators, propane distributors and industrial, utility and power plant customers.

Supply and Demand.    Supply for our trucking and NGL 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 NGL marketing business assets are geographically located within Texas, Louisiana, Oklahoma and Mississippi, the majority of activities conducted by our trucking and NGL marketing business are conducted within those states. However, our trucking and NGL marketing assets, including our firm transportation capacity and firm natural gas storage capacity, are able to provide us and third parties with access to markets outside of the Mid-Continent and 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 NGL marketing business is our natural gas and NGL purchase and resale business. Through our natural gas and NGL purchase and resale operations, we can efficiently manage the transportation and delivery of natural gas and NGLs from our gathering, processing and transportation assets and deliver them through major natural gas transportation 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.

Our trucking and NGL marketing business also uses 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

 

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

Competition.    Our trucking and NGL 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.

Marketing Segment

Our Marketing segment’s objectives are to enhance the value of our gathering and processing assets and generate incremental gross margin. These objectives are achieved primarily from the optimization of natural gas purchased on our gathering and processing assets and transported into various downstream pipelines to credit-worthy customers. Additionally, our Marketing segment transacts with various counterparties to obtain transportation and storage assets that are used to enhance existing natural gas purchases and sales

Since our gathering and intrastate wholesale customer pipeline assets are geographically located within Texas and Oklahoma, the majority of activities conducted by our Marketing segment are focused within these areas, or points downstream of these locations.

Customers.    Natural gas purchased by our Marketing business is sold to industrial, utility and power plant end use customers. In addition, gas is sold to marketing companies at various market hubs. These sales are typically priced based upon a published daily or monthly price index. Sales to end-use customers incorporate a pass-through charge for costs of transportation and additional margin to compensate us for associated services.

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

Our Marketing business uses third-party storage capacity to balance supply and demand factors within its portfolio. Our Marketing business pays third-party storage facilities and pipelines for the right to store gas for various periods of time. These contracts may be denoted as firm storage, interruptible storage or parking and lending services. These various contract structures are used to mitigate risk associated with sales and purchase contracts and to take advantage of price differential opportunities. Our Marketing business leases third-party pipeline capacity downstream from our Natural Gas assets under firm transportation contracts, which capacity is dependent on the volumes of natural gas from our natural gas assets. This capacity is leased for various lengths of time and at rates that allow our Marketing business to diversify its customer base by expanding its service territory. Additionally, this transportation capacity provides assurance that our natural gas will not be shut in, which can result from capacity constraints on downstream pipelines.

Competition.    Our Marketing segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies.

 

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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 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

 

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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.

The index as of July 1, 2012 resulted in an increase of approximately 8.6% to the Lakehead, Ozark and North Dakota portion of their indexed rates. A shipper filed a protest, challenging the proposed increase to the Lakehead rates arguing that Lakehead was not entitled to the increase. The Commission dismissed the protest and the Lakehead rates, as filed, are in effect.

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

 

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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 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 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 Texas Railroad Commission 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 Texas Railroad Commission via its Informal Complaint Process.

In Oklahoma, intrastate natural gas pipelines and gathering systems are subject to regulation by the Oklahoma Corporation Commission (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 day’s 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.

 

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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, or NGPA. At least one of our intrastate pipelines will file for FERC approval of new rates in 2014. 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, 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 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

 

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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, 2013 for transportation on the Lakehead system, the rates for transportation of light, medium and heavy crude oil from the 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 International Border near Neche, North Dakota:

        

To Clearbrook, Minnesota

   $         0.3982      $         0.4213      $         0.4622  

To Superior, Wisconsin

   $ 0.8293      $ 0.8851      $ 0.9827  

To Chicago, Illinois area

   $ 1.8070      $ 1.9428      $ 2.1811  

To Marysville, Michigan area

   $ 2.1750      $ 2.3403      $ 2.6302  

To Buffalo, New York area

   $ 2.2285      $ 2.3982      $ 2.6951  

Clearbrook, Minnesota to Chicago

   $ 1.6080      $ 1.7206      $ 1.9181  

 

(1) 

Pursuant to FERC Tariff No. 43.12.0 as filed with the FERC and with an effective date of July 1, 2013 (converted from $/m3 to $/Bbl).

The transportation rates as of December 31, 2013 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.

1998 Settlement Agreement

On December 21, 1998, the FERC issued an order in Docket No. OR99-2-000 approving an uncontested Settlement Agreement, referred to as the 1998 Settlement Agreement, between Lakehead and CAPP with respect to three agreed-upon changes to our Lakehead system’s rates: (1) a surcharge to recover costs of an expansion project known as the System Expansion Program Phase II, or SEP II; (2) a surcharge to recover costs of the Terrace expansion program; and (3) an increase in the surcharge for heavy petroleum to reflect a change in Lakehead’s operating capability to transport heavier grades of petroleum.

SEP II Surcharge

Under the Settlement Agreement with CAPP that the FERC approved in 1996 and reconfirmed in 1998, Lakehead implemented a transportation rate surcharge related to SEP II. This cost-of-service surcharge is added to the base transportation rates and is trued-up annually April 1st for actual costs and throughput from the previous calendar year and is not subject to indexing. The term of the SEP II portion of the Settlement

 

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Agreement was 15 years, beginning in 1999 and expiring December 31, 2013. Lakehead is currently in discussions regarding a new agreement.

Terrace Surcharge

Under the 1998 Settlement Agreement, the Lakehead system implemented a transportation rate surcharge for the Terrace expansion program, referred to as the Terrace Surcharge, of approximately $0.013 per barrel for light crude oil from the Canadian border to Chicago. The surcharge remained at this level through December 31, 2013, when the Terrace Surcharge expired.

Facilities Surcharge

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 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 Facilities Surcharge is intended to be utilized to include 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 and other FERC approved surcharges already in effect. The Facilities Surcharge Mechanism, or FSM, Settlement requires the Lakehead system to adjust the Facilities Surcharge annually to reflect the latest estimates for the upcoming year and to true-up the difference between estimates and actual cost and throughput data in the prior year.

The FERC permitted the Facilities Surcharge 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 Commission accepted the Lakehead system’s proposal “to submit for Commission review and approval future agreements resulting from negotiations with CAPP where the parties have agreed that recovery of costs through the Facilities Surcharge is desirable and appropriate.” At the time the FSM was initially established, four projects were included in the Facilities Surcharge:

 

  (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 Facilities Surcharge particular shipper-requested projects that are not yet in service as of April 1st of each year, provided there is an annual true-up of throughput and cost estimates. Enbridge Energy, Limited Partnership, 124 FERC ¶ 61,159 (2008). The FERC also approved the addition of four new projects to the Facilities Surcharge (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.

 

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On August 28, 2009, the FERC accepted the Supplement to the Settlement (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 (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 (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 (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 (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 December 13, 2013, Enbridge filed a Supplement to the Settlement seeking approval for recovery of the costs associated with two more projects:

 

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

 

  (20) 2014 Mainline Expansions Project.

The Eastern Access Phase 2 Mainline Expansion, or Project 19 above, has an overall capital cost of $531 million and includes a 30 inch pipeline replacement of Line 6B from Ortonville, Michigan to the US/Canada border and one new tank at Griffith, Indiana. The project is expected to add 260,000 bpd of capacity on that segment.

The 2014 Mainline Expansions, or Project 20 above, has an overall estimated capital cost of $420 million with two main components:

 

  a) The Line 67 Alberta Clipper Expansion involves pump station upgrades and two new tanks at Superior, Wisconsin which will provide an additional 120,000 bpd of capacity on Line 67 from the US/Canada border to Superior, Wisconsin at an estimated capital cost of $205 million;

 

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  b) The Line 61 Southern Access Expansion involves adding one new pump station, additional pump station upgrades, and the addition of three new tanks at Flanagan, Illinois, which will provide an additional 160,000 bpd of capacity from Superior, Wisconsin to Flanagan, Illinois at an estimated capital cost of $215 million.

For Line 67 of the 2014 Mainline Expansions, it is now anticipated that it will take longer to obtain regulatory approval than planned. A number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput.

As of December 31, 2013, the Facilities Surcharge was $0.6515 per barrel for light crude oil movements from the International border near Neche, North Dakota to Chicago, Illinois.

Other Tariff and Transportation Rate Cases

Lakehead was subject to two complaint proceedings and one protest in 2013, all three of which were initiated in 2012. On May 11, 2012, PBF Holding Company LLC and Toledo Refining Company LLC (“PBF”) filed a complaint with the FERC alleging that Enbridge Energy, Limited Partnership (“Enbridge”) was discriminating against light crude shippers in favor of heavy crude shippers by failing to move light sour crude from Line 5 to Line 6 to equalize apportionment on the two lines. In its complaint, PBF sought damages under section 16(1) of the Interstate Commerce Act for the allegedly unlawful apportionment procedures and practices of Enbridge. On June 11, 2012, Enbridge filed a Motion to Dismiss and Answer to the PBF complaint, stating that it has operated its pipelines in this manner for the past 30 years and that Enbridge believes its current method is the fairest manner to allocate capacity, maximize utilization and take into account the differences between grades of crude. On August 9, 2012, FERC set the matter for hearing, first ordering a settlement process. The settlement proceedings concluded on November 7, 2012, at which time Enbridge and PBF expressed that they were unable to settle the matter. The settlement judge issued an order terminating the settlement process and appointing an Administrative Law Judge for the hearing process, which commenced December 3, 2012. On April 26, 2013, before completion of the hearing process, PBF withdrew its complaint.

High Prairie Pipelines LLC, a subsidiary of Saddle Butte Pipeline, LLC (“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. In its order granting rehearing, the FERC stated that rehearing requests would be addressed in a future order.

On October 22, 2012, Enbridge filed a Rules and Regulations tariff, FERC Tariff No. 41.3.0 which revised Enbridge’s downstream nomination verification procedure by eliminating a frozen 24-month historical period and substituting it with the capability of each delivery facility to receive volumes from Enbridge. A number of shippers filed protests against the proposed tariff and several other shippers filed motions to intervene in the proceeding. On November 13, 2012, Enbridge filed a response to the motions to intervene and protest, stating it would not be opposed to FERC suspending the tariff for up to seven months and holding a technical conference at which to address the shipper concerns. On December 20, 2012, FERC issued an order accepting and suspending Tariff 41.3.0 and established a Technical Conference, which was held at the FERC on February 6, 2013. As a result of consultations with shippers, Enbridge filed a revised Destination Verification procedure on March 8, 2013, in its Post-Technical Conference Reply Comments. On July 18, 2013, the FERC issued an order accepting Enbridge’s revised Destination Verification procedure effect July 21, 2013.

 

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International Joint Tariff

FERC Tariff No. 45.2.0, issued May 31, 2013, revised the International Joint Tariff, or IJT, effective July 1, 2013, by increasing the transportation tolls by 0.97% and included a surcharge, adjusted for distance and crude type, of $0.2318 per cubic meter for movements of light crude from the US/Canada border to Chicago, Illinois for the recovery of costs associated with a regulatory change pursuant to Section 20.1 (i) of the Competitive Toll Settlement. The IJT provides rates applicable to the transportation of petroleum from all receipt points in western Canada on the 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 and offers transportation service to Wood River. The transportation rate for light crude oil from Cushing to principal delivery points are set forth below.

Effective August 1, 2013, FERC Tariff 51.4.0 provided a volume discount to the transfer charge for all shippers who transferred more than 10,000 barrels per month. Shippers transferring 10,000 barrels or less continued to pay 13.65 cents per barrel, while those shipper who qualified for the discount paid 4.00 cents per barrel.

On September 30, 2013, Enbridge filed FERC Tariff 51.5.0 which cancelled, effective November 1, 2013 the transfer charge at Cushing as the service is now provided by Enbridge Storage (Cushing) L.L.C. on a commercial basis.

The transportation rate for light crude oil from Cushing to principal delivery points are set forth below:

 

     Published
Transportation
Rate Per Barrel(1)
 

To Wood River

   $ 0.6221   

 

(1) 

Pursuant to FERC Tariff No. 48.3.0 as filed with the FERC on May 31, 2013, with an effective date of July 1, 2013.

The transportation rates as of December 31, 2013, outlined above, apply to light crude only. Medium and heavy crude oil transportation rates on these systems are higher to compensate for differences in the costs of shipping different types and grades of liquid hydrocarbons.

Where applicable, transportation rates are periodically adjusted as allowed under the FERC’s index methodology. This methodology allows for an adjustment of transportation rates effective July 1 of each year.

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 (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 trued-up each year to actual costs and volumes and are not subject to the

 

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FERC index 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.

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 (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 trued-up 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.

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 (FERC Docket No. OR10-19-000).

On August 15, 2012, the North Dakota system amended its Rules and Regulations tariff to modify its prorationing policy. Two years prior, on August 30, 2010, the North Dakota system amended its Rules and Regulations tariff by implementing a temporary 24-month freeze on the creation of additional Regular Shippers. The change was intended to eliminate further proliferation of New Shippers and mitigate the erosion of Regular Shipper capacity on the system. During the 24-month period commencing on October 1, 2010, shippers that had not yet attained Regular Shipper status as of that date were no longer permitted to become Regular Shippers until the later of: (i) the date on which that shipper has transported crude oil during nine of the previous 12 months or (ii) a month in which the system as a whole is not in apportionment. The North Dakota system’s Rules and Regulations tariff was approved by the FERC Order 132 FERC ¶ 61,274, issued on September 30, 2010 (Docket No. IS10-614-000). With the temporary 24-month freeze set to expire, a new tariff filed on August 15, 2012 intended to provide relief for all New Shippers who had been frozen in the New Shipper class during the freeze, but had developed sufficient history to qualify as a Regular Shipper. North Dakota intended to do this by allowing all qualifying shippers to achieve Regular Shipper status and then reserving less than 10% of capacity for New Shippers under the condition that any future expansions of capacity to Clearbrook, Minnesota would solely benefit New Shippers until such time as their access to capacity totaled at least 10% of the total available capacity to Clearbrook. Notwithstanding a protest that was filed, the Commission accepted the tariff effective September 15, 2012.

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 have resulted 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. Six protests of the project were filed with the FERC, to which Enbridge responded on November 12, 2012, reaffirming the benefits of the Sandpiper Project and the support it has received from a cross section of shippers, including 15 who signed the Offer of Settlement. 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, and the protests indicated that that hurdle was not met in this case. A revised proposal for the Sandpiper Project, including the availability of contracted space on the pipeline, is currently being offered to shippers through an open season and it is anticipated that a new Petition for Declaratory Order will be filed in 2014.

 

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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. Tariffs to allow movements on the Bakken Project and for delivery to the new Enbridge Rail (North Dakota) LLC facility at Berthold, North Dakota were filed on December 18, 2012 to be effective January 15, 2013.

On March 1, 2013, FERC Tariff 72.22.0 was filed, trueing-up 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 that 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 (Docket No. OR13-28-000) asking the FERC to throw out 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.

On May 1, 2013, FERC Tariff 72.23.0 was filed, which among other things established Little Muddy, North Dakota as a new receipt point on the system and lifted a previously implemented discount to the rates from Alexander and Trenton, North Dakota to Tioga, North Dakota. The tariff went into effect June 1, 2013.

On May 8, 2013, FERC Tariff 71.15.0 was filed, to be effective on May 9, 2013. The tariff introduced a new quality specification for the presence of hydrogen sulfide (no more than 5 parts per million) in the crude in order to protect the health and safety of North Dakota system employees. The tariff was protested by shippers who disliked the short notice provided and thought the specification was too strict; however the FERC rejected the protest and upheld the tariff due to the significant safety concerns surrounding hydrogen sulfide.

On July 5, 2013, FERC Tariff 72.25.0 was filed, to be effective on August 1, 2013. The tariff established a new delivery point at Berthold, North Dakota, connecting the North Dakota system to a merchant tankage facility provided by Enbridge Storage (North Dakota) LLC.

On July 31, 2013, FERC Tariff 71.16.0 was filed, modifying the non-performance penalty. Following the August 31, 2013 effective date, the volumetric aspect of the penalty only applies if the North Dakota system is in apportionment.

On August 30, 2013, and September 30, 2013, FERC Tariffs 72.26.0 and 72.27.0 respectively, were filed. These tariffs established initial gathering and truck unloading services and charges at Trenton, North Dakota and Stanley, North Dakota. The two $0.1046/Bbl interconnection rates resulted from shippers’ requests for pipeline interconnections to facilitate receipts into the system at those locations. The tariffs became effective October 1, 2013 and November 1, 2013.

On November 25, 2013, the North Dakota system changed its legal name from Enbridge Pipelines (North Dakota) LLC to North Dakota Pipeline Company LLC. Tariffs were filed on December 23 and December 24, 2013 with the FERC to reflect the new company name.

 

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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)(2) 
 

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

   $ 1.8739  

From Grenora, North Dakota to Clearbrook

   $ 2.0258  

From Flat Lake and Reserve, Montana to Clearbrook, Minnesota

   $ 2.0594  

From Tioga, North Dakota to Clearbrook, Minnesota

   $ 1.9072  

From Trenton, North Dakota to Clearbrook, Minnesota

   $ 2.3970  

From Alexander, North Dakota to Clearbrook, Minnesota

   $ 2.4473  

From Little Muddy, North Dakota to Clearbrook, Minnesota

   $ 2.3970  

From Grenora, North Dakota to Tioga, North Dakota

   $ 0.7116  

From Flat Lake, Montana to Tioga, North Dakota

   $ 0.7430  

From Reserve, Montana to Tioga, North Dakota

   $ 0.7430  

From Trenton, North Dakota to Tioga, North Dakota

   $ 0.8269  

From Alexander, North Dakota to Tioga, North Dakota

   $ 0.8771  

From Little Muddy, North Dakota to Tioga, North Dakota

   $ 0.8269  

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

   $ 0.2615  

From Tioga, North Dakota to Stanley, North Dakota

   $ 0.9843  

From Grenora, North Dakota to Stanley, North Dakota

   $ 1.0935  

From Reserve, Montana to Stanley, North Dakota

   $ 1.1245  

From Trenton, North Dakota to Stanley, North Dakota

   $ 1.4512  

From Alexander, North Dakota to Stanley, North Dakota

   $ 1.4976  

From Little Muddy, North Dakota to Stanley, North Dakota

   $ 1.4512  

From Berthold, North Dakota to Berthold, North Dakota

   $ 0.8121   

From Stanley, North Dakota to Berthold, North Dakota

   $ 0.8736   

From Tioga, North Dakota to Berthold, North Dakota

   $ 1.0683   

Gathering from Newburg, North Dakota or Flat Lake, Montana

   $ 0.8611  

 

(1)

Pursuant to FERC Tariff No. 72.28.0 as filed with the FERC on December 23, 2013, with an effective date of December 23, 2013.

 

(2)

The looping surcharge was modified in 2009 to extend the cost recovery period by an additional four years, which reduced the rates.

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 Title 49 of the United States Code of Federal Regulations Parts 190-199 (Pipeline Safety Act, 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.

 

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On December 29, 2006, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, referred to as 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 U.S. Department of Transportation 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.

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 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 National Transportation Safety Board, or NTSB, investigation, such as those associated with Line 6B near Marshall, MI and Line 14 near Grand Marsh, WI could have a material impact on system throughput or compliance costs. As part of the Corrective Action Order 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

 

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situations. Nevertheless, significant operating expenses and capital expenditure could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the capabilities of our current pipeline control system or other safety equipment.

Environmental Regulation

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

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

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

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

Air and Water Emissions.    Our operations are subject to the federal Clean Air Act, or CAA, and the federal 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. In January 2010, the Environmental Protection Agency, or EPA, published that the effective date of the Spill Prevention, Control, and Countermeasures Rule Amendments would be November 10, 2010. However, on October 7, 2010, the EPA issued an extension to the compliance date to November 10, 2011. While the operations of our pipeline facilities are subject to the rule, we prepared the necessary plans for compliance prior to the November 2011 effective date. In 2009, the EPA published the Greenhouse Gas Recordkeeping and Reporting Rule, which requires applicable facilities to record and report greenhouse gas emissions from combustion sources beginning January 1, 2010. As a part of the reporting rule, in November 2010, the EPA published the requirements for reporting emissions from Petroleum and Natural Gas Systems beginning January 1, 2011. While the operations of our pipelines are subject to the rule, we do not believe that the rule requirements will have a material effect on our operations. Annual emissions from combustion activities in 2010 were reported prior to the September 30, 2011 deadline. Facilities subject to existing Greenhouse Gas Reporting rules reported emissions prior to the March 31, 2012 deadline for 2011 emissions. Facilities subject to the new reporting rules in 2011 reported emissions prior to the September 28, 2012 deadline. On August 23, 2011, the EPA proposed New Source Performance Standards (NSPS), Subpart OOOO, for volatile organic compounds, or VOC, and sulfur dioxide, or SO2, emissions from the Oil and Natural Gas Sector. The final standards were

 

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published and became effective on August 16, 2012. The compliance dates range from October 15, 2012, to April 15, 2015, dependent on the affected equipment. 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.

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.

Hazardous Substances and Waste Management.    The federal 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-

 

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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, 2014. The insurance coverage 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 and other Enbridge subsidiaries.

The coverage limits and deductible amounts at December 31, 2013 for our insurance policies:

 

Insurance Type

   Coverage Limits      Deductible
Amount
 
     (in millions)  

Property and business interruption

   Up to $ 700.0       $ 10.0  

General liability

   Up to $ 685.0       $ 0.1  

Pollution liability (as included under General Liability)

   Up to $ 685.0       $ 10.0  

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 the Exchange Act, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not part of this report.

 

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Item 1A.    Risk Factors

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

RISKS RELATED TO OUR BUSINESS

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

 

   

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.

 

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

Currently, we are parties to certain International Swaps and Derivatives Association, Inc., or ISDA®, agreements associated with the derivative financial instruments we use to manage our exposure to fluctuations in commodity prices. These ISDA® agreements require us to provide assurances of performance if our counterparties’ exposure to us exceeds certain levels or thresholds. We generally provide letters of credit to satisfy such requirements. At December 31, 2013, we have provided $76.1 million in the form of letters of credit as assurances of performance for our then outstanding derivative financial instruments. In the event that our credit ratings were to decline to the lowest level of investment grade, as determined by S&P and Moody’s, we would be required to provide letters of credit in substantially greater amounts to satisfy the requirements of our ISDA® agreements. For example if our credit ratings had been at the lowest level of investment grade at December 31, 2013, we would have been required to provide additional letters of credit in the aggregate amount of $14.8 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;

 

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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 during periods when we record net losses or may make no distributions during periods when 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;

 

   

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;

 

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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 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:

 

   

cost inflation;

 

   

labor availability;

 

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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.

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 are greenhouse gas emissions and environmental monitoring and reclamation. Though industry associations have stated that they are not opposed to changes in policy and regulation, the risk of any sort of regulation that may curtail oil sands development or adversely impact the oil and gas industry remains a risk.

Volatility in commodity prices is a concern for the oil sands industry. The relatively high costs and large up front capital investments required by oil sands mega projects makes capital cost recovery a key consideration for future development. Wide commodity price spreads have impacted producer netbacks and margins over the past year and largely result 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 guaranteed.

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, which came into service in the third quarter of 2010.

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.

 

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

Our gas marketing operations involve market and regulatory risks.

As part of our natural gas 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;

 

   

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 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.

At December 31, 2013, approximately 57% of our gross margin was attributable to contracts with some degree of commodity price exposure. In addition under our keep-whole/wellhead purchase contracts, we have direct exposure to both natural gas and NGL prices because our costs are dependent on the price of natural gas and our revenues are dependent on the price of NGL’s. 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.

 

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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 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 requiring difficult and costly actions. Our failure to comply with these laws, regulations and operating permits can result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. Our operation of liquid petroleum and natural gas gathering, processing, treating and transportation facilities exposes us to the risk of incurring significant environmental costs and liabilities. Additionally, operational modifications,

 

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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. 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. At the federal level, the United States Congress has in the past and may in the future consider legislation to reduce emissions of greenhouse gases. On September 22, 2009, the EPA issued a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Subsequently, on November 30, 2010, the EPA issued a supplemental rulemaking that expanded the types of industrial sources that are subject to or potentially subject to EPA’s mandatory greenhouse gas emissions reporting requirements to include petroleum and natural gas systems.

The April 2010 issuance of regulations to control the greenhouse gas emissions from light duty motor vehicles (the “tailpipe rule”) automatically triggered provisions of the Clean Air Act of 1970, as amended, or CAA, that, in general, require stationary source facilities that emit more than 250 tons per year of carbon dioxide equivalent to obtain permits to demonstrate that best practices and technology are being used to minimize greenhouse gas emissions. On May 13, 2010, the EPA issued the “tailoring rule,” which served to increase the greenhouse gas emissions threshold that triggers the permitting requirements for major new (and major modifications to existing) stationary sources. Under a phased-in approach, for most purposes, new permitting provisions are required for new facilities that emit 100,000 tons per year or more of carbon dioxide equivalent, or CO2e, and existing facilities making changes that would increase greenhouse gas emissions by 75,000 CO2e. The EPA has also indicated in rulemakings that it may further reduce the current regulatory thresholds for greenhouse gas emissions, making additional sources subject to permitting. On June 26, 2012, in Coalition for Responsible Regulation v. EPA, the U.S. Circuit Court of Appeals for the District of Columbia circuit upheld the bases for the tailoring rule, and ruled that no petitioners had standing to challenge it. On April 18, 2013, the plaintiffs filed a petition for review of that decision by the U.S. Supreme Court.

In addition, more than one-third of the states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap-and-trade programs. Although many of the state-level initiatives have, to date, focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that in the future sources in states where we operate, such as our gas-fired compressors, could become subject to greenhouse gas-related state regulations. Depending on the particular program, we could in the future be required to purchase and surrender emission allowances or otherwise undertake measures to

 

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reduce greenhouse gas emissions. Any additional costs or operating restrictions associated with new legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows, in addition to the demand for our services.

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

Operation of complex pipeline systems, gathering, treating, processing and trucking operations involves many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of the facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes, floods, landslides or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, any of which could also result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. Costs of pipeline seepage over time may be mitigated through insurance, however, if not discovered within the specified insurance time period we would incur full costs for the incident. 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.

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.

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

 

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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 oil and gas hedging transactions. These statutory requirements must be implemented through regulations, primarily through rules to be adopted by the Commodity Futures Trading Commission, or the CFTC. The Dodd-Frank Act provisions may change fundamentally the way many swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which many swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. A considerable number of market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants are subject to new reporting and recordkeeping requirements.

The impact of the Dodd-Frank Act on our hedging activities is uncertain at this time, and the CFTC has not yet promulgated final regulations implementing some of the key provisions. Although we do not believe we will need to register as a swap dealer or major swap participant, and do not believe we will be subject to the new requirements to trade on an exchange or swap execution facility or to clear swaps through a central counterparty, we may have new regulatory burdens. Moreover, the changes to the swap market as a result of Dodd-Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps.

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

 

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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 lender, entered into a $250 million Working Capital Loan Agreement (the “Working Capital Credit Facility”) with Midcoast Operating. We, as financial support provider, also 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 Working Capital Credit facility and financial support agreement are subordinated to the rights of the lenders under 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 these agreements. 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.

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

 

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

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

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

 

   

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;

 

   

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;

 

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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.

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.

 

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Additionally, the public sale by our General Partner of a significant portion of the Class A or Class B common units that it 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 currently held by our General Partner 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.

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

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

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

 

   

general creditors;

 

   

trade creditors;

 

   

secured creditors;

 

   

taxing authorities; and

 

   

creditors holding guarantees.

 

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

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

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

The holders of our Series 1 Preferred Units, or Preferred Units, have a preferential right to distributions prior to distributions to the holders of our Class A common units. 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, 2014. 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.

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

 

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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

The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If we were to be treated as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders could be substantially reduced.

As long as we qualify to be treated as a partnership for federal income tax purposes, we are not subject to federal income tax. Although a publicly-traded limited partnership is generally treated as a corporation for federal income tax purposes, a publicly-traded partnership such as us can qualify to be treated as a partnership for federal income tax purposes under current law so long as for each taxable year at least 90% of our gross income is derived from specified investments and activities. We believe that we qualify to be treated as a partnership for federal income tax purposes because we believe that at least 90% of our gross income for each taxable year has been and is derived from such specified investments and activities. Although we intend to meet this gross income requirement, we may not find it possible, regardless of our efforts, to meet this gross income requirement or may inadvertently fail to meet this gross income requirement. If we do not meet this gross income requirement for any taxable year and the Internal Revenue Service, or IRS, does not determine that such failure was inadvertent, we would be treated as a corporation for such taxable year and each taxable year thereafter. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or certain other matters affecting us.

Additionally, current law may change so as to cause us to be treated as a corporation for federal income tax purposes without regard to our sources of income or otherwise subject us to entity-level taxation. Legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Moreover, any modification to the federal income tax laws and interpretations thereof may be applied retroactively.

If we were to be 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%. Under current law, distributions to unitholders would generally be taxed as corporate distributions, and no income, gain, loss or deduction would flow through to our unitholders. If we were treated as a corporation at the state level, we may

 

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also be subject to the income tax provisions of certain states. Moreover, 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 or other forms of taxation. For example, we are required to pay Texas franchise tax at a minimum effective rate of 0.7% of our gross income apportioned to Texas in the prior year.

If we become subject to federal income tax and additional state taxes, the additional taxes we pay will reduce the amount of cash we can distribute each quarter to the holders of our Class A and B common units and the number of i-units that we will distribute quarterly. Therefore, our treatment as a corporation for federal income tax purposes or becoming subject to a material amount of additional state taxes could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. Moreover, our payment of additional federal and state taxes could materially and adversely affect our ability to make payments on our debt securities.

If the IRS contests our curative tax allocations or other federal income tax positions we take, the market for our Class A common units may be impacted and the cost of any IRS contest will reduce our cash available for distribution or payments on our debt securities.

Our partnership agreement allows curative allocations of income, deduction, gain and loss by us to account for differences between the tax basis and fair market value of property at the time the property is contributed or deemed contributed to us and to account for differences between the fair market value and book basis of our assets existing at the time of issuance of any Class A common units. If the IRS does not respect our curative allocations, ratios of taxable income to cash distributions received by the holders of Class A common units will be materially higher than previously estimated.

The IRS may adopt positions that differ from the positions we have taken or may take on certain tax matters. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we have taken or may take. A court may not agree with some or all of the positions we have taken or may take. Any contest with the IRS may materially and adversely impact the market for our Class A 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 cash available for distribution or payments on our debt securities.

The tax liability of our unitholders could exceed their distributions or proceeds from sales of Class A common units.

Because our unitholders will generally be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income tax and, in some cases, state and local income taxes on their allocable share of our income, even if they do not receive cash distributions from us. Unitholders will not necessarily receive cash distributions equal to the tax on their allocable share of our taxable income.

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

If a unitholder disposes of Class A common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s tax basis in those Class A common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their Class A common units, the amount, if any, of such prior excess distributions with respect to their Class A common units sold will, in effect, become taxable income to the unitholder if the Class A common units are sold at a price greater than the unitholder’s tax basis in those Class A common units, even if the price the

 

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unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, 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, if a unitholder sells Class A common units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

As a result of investing in our Class A common units, a unitholder may become subject to state and local taxes and return filing requirements in the states where we or our subsidiaries own property and conduct business.

In addition to federal income taxes, a unitholder 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 or our subsidiaries conduct business or own property now or in the future, even if such unitholder does 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 or our subsidiaries own property and conduct business in the states of Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, New York, Pennsylvania, South Carolina, North Carolina, North Dakota, Oklahoma, Tennessee, Texas, West Virginia, and Wisconsin. Most of these states impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may acquire property or conduct business in additional states or in foreign jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all required United States federal, foreign, state and local tax returns.

Ownership of Class A common units raises issues for tax-exempt entities and other investors.

An investment in our Class A common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts, known as IRAs, Keogh plans and other retirement plans, regulated investment companies and foreign persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from United States federal income tax, including IRAs and other retirement plans, will be “unrelated business taxable income” and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable tax rate, and non-United States persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities and non-United States persons should consult their tax adviser before investing in our Class A common units.

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

When we issue additional Class A common 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 Class A 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 income, gain, loss and deduction between the General Partner and certain of our unitholders.

 

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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 gain from our unitholders’ sale of Class A common units and could have a negative impact on the value of the Class A common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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

We will be considered to have been terminated for United States federal tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. Our 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) for one fiscal year and could result in a significant deferral of depreciation deductions available 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 such 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 tax purposes. If treated as a new partnership for federal tax purposes, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

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

Because we cannot match transferors and transferees of our Class A common units and to maintain the uniformity of the economic and tax characteristics of our Class A common units, we have adopted certain depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. These positions may result in an understatement of deductions and losses and an overstatement of income and gain to our unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding Class A common units. A subsequent holder of those Class A common units is entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). However, because we cannot identify these Class A common units once they are traded by the initial holder, we do not give any subsequent holder of a Class A common unit any such amortization deduction. This approach understates deductions available to those unitholders who own those Class A common units and results in a reduction in the tax basis of those Class A common units by the amount of the deductions that were allowable but were not taken.

The IRS may challenge the manner in which we calculate our unitholder’s basis adjustment under Internal Revenue Code Section 743(b). If so, because neither we nor a unitholder can identify the Class A common units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling Class A common units within the period under audit as if all unitholders owned Class A common units with respect to which allowable deductions were not taken. Any position we take that is inconsistent with applicable Treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to this position or other positions we may take could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of Class A common units and could have a negative impact on the value of the Class A common units or result in audit adjustments to our unitholders’ tax returns.

 

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

Because a unitholder whose Class A common units are loaned to a “short seller” to cover a short sale of Class A common units may be considered as having disposed of those Class A common units, such unitholder may no longer be treated as a partner with respect to those Class A common units during the period of the loan to the short seller and the unitholder may 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 Class A common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Class A 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 Class A common units.

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.

Item 3.    Legal Proceedings

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

Item 4.    Mine Safety Disclosures

None.

 

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PART II

 

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

Our Class A common units are listed and traded on the NYSE, the principal market for the Class A common units, under the symbol EEP. The quarterly price ranges per Class A common unit and cash distributions paid per unit for 2013 and 2012 are summarized as follows:

 

     First      Second      Third      Fourth  

2013 Quarters

           

High

   $ 30.68      $ 31.17      $ 33.49      $ 30.96  

Low

   $ 27.01      $ 28.01      $ 28.97      $ 28.41  

Cash distributions paid

   $ 0.54350      $ 0.54350      $ 0.54350      $ 0.54350  

2012 Quarters

           

High

   $ 33.85      $ 31.43      $ 31.12      $ 30.64  

Low

   $ 30.42      $ 27.75      $ 28.26      $ 26.88  

Cash distributions paid

   $ 0.53250      $ 0.53250      $ 0.54350      $ 0.54350  

On February 14, 2014, the last reported sales price of our Class A common units on the NYSE was $27.69. At January 31, 2014, there were approximately 92,000 Class A common unitholders, of which there were approximately 1,100 registered Class A common unitholders of record. There is no established public trading market for our Class B common units, all of which are held by the General Partner, or our i-units, all of which are held by Enbridge Management.

 

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Item 6.    Selected Financial Data

The following table sets forth, for the periods and at the dates indicated, 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,  
     2013     2012     2011     2010     2009  
    (in millions, except per unit amounts)  

Income Statement Data:(2)(5)(6)(7)(8)(9)(10)(11)

  

   

Operating revenues

  $ 7,117.1     $ 6,706.1     $ 9,109.8     $ 7,736.1     $ 5,731.8  

Operating expenses

    6,676.7       5,812.9       8,113.0       7,608.8       5,115.2  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    440.4       893.2       996.8       127.3       616.6  

Interest expense

    320.4       345.0       320.6       274.8       228.6  

Allowance for equity used during construction

    43.1       11.2             15.3       12.6  

Other income (expense)

    16.0       (1.2     6.5       2.2       0.8  

Income tax expense

    18.7       8.1       5.5       7.9       8.5  

Noncontrolling interest

    88.3       57.0       53.2       60.6       11.4  

Series 1 preferred unit distributions

    58.2                          

Accretion of discount on Series 1 preferred units

    9.2                          
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

  $ 4.7     $ 493.1     $ 624.0     $ (198.5   $ 381.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) allocable to limited partner interest

  $ (122.7   $ 369.2     $ 520.5     $ (260.1   $ 260.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations per limited partner unit (basic and diluted) (1)

  $ (0.39   $ 1.27     $ 1.99     $ (1.09   $ 1.12  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations per limited partner unit (diluted) (1)

  $ (0.39   $ 1.27     $ 1.99     $ (1.09   $ 1.12  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions paid per limited partner unit

  $     2.1740     $     2.1520     $     2.0925     $     2.0240     $     1.9800  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Financial Position Data (at year end):(2)(3)(4)(5)(6)(7)(8)(9)

         

Property, plant and equipment, net

  $ 13,176.8     $ 10,937.6     $ 9,439.4       8,641.6       7,716.7  

Total assets

    14,901.5       12,796.8       11,370.1       10,441.0       8,988.3  

Long-term debt, excluding current maturities

    4,777.4       5,501.7       4,816.1       4,778.9       3,791.2  

Notes payable to General Partner

    318.0       330.0       342.0       347.4       269.7  

Partners’ capital:

         

Series 1 preferred units

    1,160.7                          

Class A common units

    2,979.0       3,590.2       3,386.7       2,641.0       2,884.9  

Class B common units

    65.3       83.9       82.2       64.9       78.6  

Class C units (12)

                             

i-units

    1,291.9       801.8       728.6       579.1       588.8  

General Partner

    301.5       299.0       285.6       256.8       251.1  

Accumulated other comprehensive income (loss)

    (76.6     (320.5     (316.5     (121.7     (74.6

Noncontrolling interest

    1,975.6       793.5       445.5       465.4       341.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital

  $ 7,697.4     $ 5,247.9     $ 4,612.1     $ 3,885.5     $ 4,069.9  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flow Data:(2)(3)(4)(5)(6)(7)(8)

         

Cash flows provided by operating activities

  $ 1,212.4     $ 851.0     $ 1,045.6     $ 377.9     $ 728.4  

Cash flows used in investing activities

    2,642.9       1,906.6       1,099.0       1,427.8       1,173.6  

Cash flows provided by financing activities

    1,367.4       860.6       331.4       1,051.2       248.9  

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

    2,410.8       1,739.9       1,091.8       1,429.5       1,292.1  

 

(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 limited partner unit: 2013, $144.1 million; 2012, $129.3 million; 2011, $104.5 million; 2010, $61.6 million; and 2009, $57.1 million.

 

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(2) 

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

 

Date of Acquisition / Disposition

  

Description of Acquisition / Disposition

September 2010

   Acquisition of the Elk City system in Oklahoma and Texas.

November 2009

   Disposition of natural gas pipelines located predominately outside of Texas.

May 2009

   Acquisition of a portion of a crude oil pipeline system running from Flanagan, Illinois to Griffith, Indiana.

January 2009

   Disposition of an offshore natural gas pipeline.

 

(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 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, 2013 we made the following debt repayments:

     – $200.0 million of our 4.750% senior notes.

 

 

For the year ended December 31, 2012 we made the following debt repayments:

     – $100.0 million of our 7.900% senior notes.

 

 

For the year ended December 31, 2011 we made the following debt repayments:

     – $31.0 million of our First Mortgage Notes;

 

 

For the year ended December 31, 2010 we made the following debt repayments:

     – $31.0 million of our First Mortgage Notes;

 

 

For the year ended December 31, 2009 we made the following debt repayments:

     – $31.0 million of our First Mortgage Notes;
     – $214.7 million of our Zero Coupon Notes;
     – $130.0 million of our Hungary Note; and
     – $175.0 million of our 4.000% senior 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  

October 2009

     Class A         42,490      $ 1.0  

 

 

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
     Amount of Distribution
of Class C Units

to Class C Unitholders
     Retained from
General Partner
     Distribution of
Cash
 

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  

2009

   $ 61.1      $     60.3      $     2.4      $     395.0  

 

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The quarterly in-kind distributions of 3.8 million, 2.6 million, 2.4 million, 2.5 million and 3.3 million i-units during 2013, 2012, 2011, 2010 and 2009, respectively, in lieu of cash distributions; and

 

 

The quarterly in-kind distributions of 1.6 million Class C units during 2009, in lieu of cash distributions.

 

(6) 

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. In exchange for a 66.67% ownership interest in the Alberta Clipper Pipeline, Enbridge, through our General Partner, funded approximately two-thirds of both the debt financing and equity requirement for the project in return for approximately two-thirds of the earnings and cash flows. For our 33.33% ownership of the Alberta Clipper Pipeline, we funded approximately one-third of the debt financing and required equity of the project, for which we are entitled to approximately one-third of the project’s earnings and cash flows. As a result of this joint funding arrangement, 66.67% of earnings associated with the Alberta Clipper Pipeline are attributable to our General Partner and presented as “Noncontrolling interest” in our consolidated statements of income and consolidated statement of financial position.

 

     In August 2009, we applied the provisions of regulatory accounting to our Alberta Clipper Pipeline. In conjunction with our application of the provisions of regulatory accounting, we recorded an allowance for equity during construction, referred to as AEDC, of $15.3 million and $12.6 million for the years ended December 31, 2010 and 2009, which is recorded in “Other income” in our consolidated statements of income. The Alberta Clipper Pipeline was put into service in 2010; therefore no AEDC was recorded in 2011.

 

(7) 

Operating results for the years ended December 31, 2013, 2012 and 2011, 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, 2013, 2012, 2011 and 2010 we will incur aggregate gross costs of $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, 2013, 2012 and 2011, we recognized $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 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, 2013, 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.

 

(8) 

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.

 

(9) 

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 as discussed in Note 14. Trucking and NGL Marketing Business Accounting Matters.

 

(10) 

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.

 

(11) 

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 $2.5 billion and $2.4 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 AEDC of $33.3 million and $4.7 million for the years ended December 31, 2013 and 2012, respectively, which is recorded in “Other income” in our consolidated statements of income.

 

(12) 

In October 2009, we effected the conversion of all our outstanding Class C units into Class A common units in accordance with the terms of our partnership agreement.

 

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

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes 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 three business segments: Liquids, Natural Gas and Marketing. 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, Midcoast Energy Partners, L.P., or MEP. On November 13, 2013, MEP completed its initial public offering, or 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 the operating subsidiary of MEP, or 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.

 

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The following table reflects our operating income by business segment and corporate charges for each of the years ended December 31, 2013, 2012 and 2011:

 

     December 31,  
      2013     2012     2011  
     (in millions)  

Operating Income (loss)

      

Liquids

   $     392.6     $ 706.8     $ 816.2  

Natural Gas

     57.7       200.1       183.6  

Marketing

     (2.3     (11.4     (0.8

Corporate, operating and administrative

     (7.6     (2.3     (2.2
  

 

 

   

 

 

   

 

 

 

Total Operating Income

     440.4       893.2       996.8  

Interest expense

     320.4       345.0       320.6  

Allowance for equity used during construction

     43.1       11.2        

Other income (expense)

     16.0       (1.2     6.5  

Income tax expense

     18.7       8.1       5.5  
  

 

 

   

 

 

   

 

 

 

Net income

     160.4       550.1       677.2  

Less: Net income attributable to:

      

Noncontrolling interest

     88.3       57.0       53.2  

Series 1 preferred unit distributions

     58.2              

Accretion of discount on Series 1 preferred units

     9.2                
  

 

 

   

 

 

   

 

 

 

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

   $ 4.7     $     493.1     $     624.0  
  

 

 

   

 

 

   

 

 

 

Contractual arrangements in our Liquids, Natural Gas and Marketing 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. These fluctuations can be significant if commodity prices experience significant volatility. We employ derivative financial instruments to hedge a portion of our commodity position and to reduce our exposure to fluctuations in crude oil, natural gas and NGL 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.

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 business for the year ended December 31, 2013 decreased $314.2 million, as compared with the same period in 2012, primarily due to the following:

 

   

Increased environmental costs, net of insurance recoveries, of $365.0 million for the year ended December 31, 2013 when compared to the same period of 2012;

 

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Increased “Operating and administrative” expenses of $104.7 million primarily due to:

 

  Increased cost related to hydrotesting on Line 14 of $57.7 million;

 

  Increased workforce related costs and other allocated expenses of $14.7 million;

 

  Increased property tax expenses of $10.2 million; and

 

  Increased facility integrity costs of $5.9 million; and

 

   

Increased depreciation expense of $34.9 million for the year ended December 31, 2013, directly attributable to additional assets placed into service since 2012.

The above factors were partially offset for the year ended December 31, 2013, as compared with the year ended December 31, 2012 due to:

 

   

Increased operating revenue of $157.4 million due to higher indexed tariff rates on our Lakehead, North Dakota and Ozark systems and increased SEPII rates from recovery of integrity costs;

 

   

Increased operating revenue of $41.7 million due to revenue from ship or pay agreements on the North Dakota systems;

 

   

Increased operating revenue of $19.4 million for fees collected from our Berthold Rail system; and

 

   

Increased operating revenue of $16.4 million for fees collected from our Cushing storage terminal facility;

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. 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. 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, 2013 decreased $142.4 million, as compared with the year ended December 31, 2012, primarily due to the following:

 

   

Decreased gross margin of approximately $57.0 million due to reduced pricing spreads between the NGLs purchased at Conway and the NGLs sold at Mont Belvieu market hubs;

 

   

Decreased gross margin from keep-whole processing earnings of $27.1 million due to a decline in total NGL production;

 

   

Decreased gross margin of approximately $27.0 million due to reduced production volumes;

 

   

Decreased gross margin of approximately $8.0 million due to changes in estimated to actual adjustments;

 

   

Decreased gross margin of $7.2 million related to prior year revenue allocation corrections. These allocation corrections provided additional revenues recognized during the year ended December 31, 2012, with no similar additional revenues recognized during the year ended December 31, 2013;

 

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Decreased gross margin of $4.5 million in non-cash, mark-to-market net losses from derivative instruments that do not qualify for hedge accounting treatment;

 

   

Decreased gross margin of approximately $4.0 million due to changes in physical measurement adjustments; and

 

   

Increased depreciation expense of $8.3 million due to additional assets that were placed into service in 2012 and 2013.

The above factors were partially offset for the year ended December 31, 2013, as compared with the year ended December 31, 2012 due to:

 

   

Decreased current year costs of $7.5 million for the investigation related to accounting misstatements at our trucking and NGL marketing subsidiary recorded for the year ended December 31, 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; 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.

Marketing

Our Marketing segment provides supply, transmission, storage and sales services to producers and wholesale customers on our natural gas gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Our Marketing activities are primarily undertaken to realize incremental revenue on gas purchased at the wellhead, increase pipeline utilization and provide other services that are valued by our customers.

The operating results of our Marketing business for the year ended December 31, 2013 increased $9.1 million, as compared with the year ended December 31, 2012. The increase in operating results of our Marketing business was the improvement of natural gas price differences between the supply and market locations where we buy and sell natural gas. These larger differences enabled us to increase our margins in certain circumstances. This was facilitated by an increase in natural gas prices for the year ended December 31, 2013, when compared to the year ended December 31, 2012.

Also contributing to the increase in operating results of our Marketing segment, for the year ended December 31, 2013, was the expiration of certain transportation fees for natural gas being transported on a third party pipeline. Additionally, we recorded only $0.4 million of non-cash charges in inventory to reduce the cost basis of our natural gas inventory to net realizable value, for the year ended December 31, 2013, compared with $2.0 million of similar charges recorded for the year ended December 31, 2012.

Derivative Transactions and Hedging Activities

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

 

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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—“Operating revenue” and “Power”

 

   

Natural Gas and Marketing segments commodity-based derivatives—“Cost of natural gas” and “Operating revenue”

 

   

Corporate interest rate derivatives—“Interest expense”

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,  
      2013     2012     2011  
     (in millions)  

Liquids segment

      

Non-qualified hedges

   $ (3.9   $ 1.3     $ 14.4  

Natural Gas segment

      

Hedge ineffectiveness

     3.3       3.1       (5.3

Non-qualified hedges

     (3.5     1.2       21.1  

Marketing

      

Non-qualified hedges

     (2.8     (3.1     0.7  
  

 

 

   

 

 

   

 

 

 

Commodity derivative fair value net gains (losses)

     (6.9     2.5       30.9  

Corporate

      

Hedge ineffectiveness

     (21.5     (20.5     (0.3

Non-qualified interest rate hedges

     (0.2     (0.5     (0.5
  

 

 

   

 

 

   

 

 

 

Derivative fair value net gains (losses)

   $ (28.6   $ (18.5   $ 30.1  
  

 

 

   

 

 

   

 

 

 

 

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RESULTS OF OPERATIONS—BY SEGMENT

Liquids

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

 

      December 31,  
      2013     2012     2011  
     (in millions)  

Operating Results

      

Operating revenues

   $ 1,519.9     $ 1,345.8     $ 1,285.4  
  

 

 

   

 

 

   

 

 

 

Environmental costs, net of recoveries

     273.7       (91.3     (112.9

Oil measurement adjustments

     (26.7     (11.5     (63.4

Operating and administrative

     487.7       383.0       303.6  

Power

     147.7       148.8       144.8  

Depreciation and amortization

     244.9       210.0       197.1  
  

 

 

   

 

 

   

 

 

 

Operating expenses

     1,127.3       639.0       469.2  
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ 392.6     $ 706.8     $ 816.2  
  

 

 

   

 

 

   

 

 

 

Operating Statistics

      

Lakehead system:

      

United States(1)

     1,427       1,405       1,327  

Province of Ontario(1)

     389       385       373  
  

 

 

   

 

 

   

 

 

 

Total Lakehead system delivery volumes(1)

     1,816       1,790       1,700  
  

 

 

   

 

 

   

 

 

 

Barrel miles (billions)

     487       480       450  
  

 

 

   

 

 

   

 

 

 

Average haul (miles)

     735       732       725  
  

 

 

   

 

 

   

 

 

 

Mid-Continent system delivery volumes(1)

     201       223       226  
  

 

 

   

 

 

   

 

 

 

North Dakota system:

      

Trunkline

     168       203       193  

Gathering

     3       3       4  
  

 

 

   

 

 

   

 

 

 

Total North Dakota system delivery volumes(1)

     171       206       197  
  

 

 

   

 

 

   

 

 

 

Total Liquids segment delivery volumes(1)

     2,188       2,219       2,123  
  

 

 

   

 

 

   

 

 

 

 

(1) 

Average barrels per day in thousands.

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 Federal Energy Regulatory Commission, or 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 application of the index allowed by FERC. The rate increase effective April 1, 2013 primarily resulted from the annual tariff rate adjustment for our Lakehead system to reflect our projected costs and throughput for 2013, true-

 

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ups for the prior year for the Lakehead system and recovery of costs related to several of our major capital projects and SEPII 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. These long-term ship-or-pay contracts contain make-up-rights. Make-up-rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiration periods. We recognize revenue associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires, or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.

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.

Operating revenue of our Liquids business was negatively impacted for the year ended December 31, 2013 when compared with the same period in 2012 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 to 2.188 million barrels per day, or Bpd, for the year ended December 31, 2013 from 2.219 million Bpd for the year ended 2012. The decrease was driven by lower North Dakota volumes which decreased due to large pricing differences that incented some shippers to move by rail rather than by pipeline as well as pressure restrictions on our Mid-Continent system. Decreases on our North Dakota and Mid-Continent systems were offset by increasing volumes on our Lakehead system which realized higher volumes due to the growth of the Canadian Oil Sands. Operating revenue was also negatively impacted by $24.9 million as a result of regulatory true-ups related to the Southern Access surcharge embedded in the Lakehead toll revenues. Delivery volumes were forecasted to be higher in the April 1, 2013 toll filing as compared to actual volumes causing this negative impact. These amounts will be trued up and recovered in the Lakehead tariff that will be effective April 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.

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 business increased $104.7 million for the year ended December 31, 2013 when compared with the same period in 2012 primarily due to the increased costs of $57.7 million related to a hydrostatic test we performed on Line 14. 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

 

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Corrective Action Order required us to take certain corrective actions, some of which were done during 2013 and some are still ongoing, as part of an overall plan for our Lakehead system. As part of this plan, we performed hydrostatic testing of Line 14 during the third quarter of 2013. As discussed above, a portion of these costs have been recovered through our Lakehead tariff and the remainder will be recovered in future periods.

Operating and administrative expenses for our Liquids business increased also due to the following:

 

   

Increased workforce related costs and other allocated expenses of $14.7 million;

 

   

Increased property tax expenses of $10.2 million; and

 

   

Higher costs related to our integrity program of $5.9 million.

Over the past several years, we have focused on achieving pipeline industry leading performance in the areas of public and worker safety, operations and pipeline systems integrity. We have implemented initiatives such as our operational risk management plan, which puts emphasis on areas such as emergency response, pipeline integrity, pipeline control and leak detection systems and we have increased our internal inspection frequency and hired more personnel in field operations to ensure we meet this overriding objective. These efforts have increased our operating cost spending relative to prior years. We expect these costs to be an ongoing obligation to achieve and maintain our goal of best in class safety performance.

The increase in depreciation expense of $34.9 million for the year ended December 31, 2013 is directly attributable to the additional assets we have placed in service during 2013 and 2012. 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 life was extended due to additional reserve growth and pipeline connectivity needs. The impact on future periods will be an annual reduction in depreciation expense of $16.8 million.

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

The operating revenue of our Liquids segment increased for the year ended December 31, 2012 when compared with the same period in 2011, partially due to higher average daily delivery volumes on our Lakehead and North Dakota systems when compared to the same period in 2011. The overall increase in average delivery volumes on our systems increased operating revenues by $25.1 million for our Liquids segment. The total average daily deliveries from our liquid systems increased over 4%, to 2.219 million barrels per day, or Bpd, for the year ended December 31, 2012 from 2.123 million Bpd for the year ended 2011. The increase in average deliveries on our liquids systems was primarily derived from increases of crude oil supplies from conventional sources as well as strong refinery utilization in PADD II.

Our operating revenue was positively impacted by the filing of tariffs to increase the rates for our Lakehead, North Dakota and Ozark systems with Federal Energy Regulatory Commission, or FERC, that became effective July 1, 2012. These rate increases resulted from application of the index allowed by FERC. This change in index comprises approximately $17.0 million of the increase in operating revenue for the year ended December 31, 2012 when compared to the same period in 2011.

Our operating revenue increased by $14.9 million during the year ended December 31, 2012 due to the collection of fees from our Cushing storage terminal facilities, with the majority of these incremental revenues coming from storage facilities which were placed into service in 2012.

In addition, our operating revenues increased by $11.8 million due to higher recovery of capital costs we recovered through our annual tolls under our Facilities Surcharge Mechanism, or FSM, related to the Line 6B Pipeline Integrity Plan for the year ended December 31, 2012 compared to the same period in 2011.

 

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The operating revenue of our Liquids business was negatively impacted for the year ended December 31, 2012 when compared with the same period in 2011 by a $13.1 million decrease in unrealized, non-cash, mark-to-market net gains for year ended December 31, 2012, related to derivative financial instruments as compared with the same period in 2011, due to changes in average forward prices of crude oil for the respective periods. 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 to 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.

The operating and administrative expenses of our Liquids business increased $79.4 million for the year ended December 31, 2012 when compared with the same period in 2011 primarily due to the following:

 

   

Increased workforce related costs and other allocated expenses of $28.2 million;

 

   

Increased support costs of $16.0 million related to professional and regulatory expenses, maintenance, supplies and other outside services;

 

   

Increased property tax expenses of $14.8 million; and

 

   

Higher costs related to our integrity program of $11.2 million.

Over the past several years, Enbridge and the Partnership have focused on achieving pipeline industry leading performance in the areas of public and worker safety, operations and pipeline systems integrity. We have implemented initiatives such as our operational risk management plan, which puts emphasis on areas such as emergency response, pipeline integrity, pipeline control and leak detection systems as well as we have increased our internal inspection frequency and hired more personnel in field operations to ensure we meet this overriding objective. These efforts have increased our operating cost spending relative to prior years. For example, during 2012, we worked with an industry leading safety consultant to assist us with enhancing safety structure and processes. All of these programs and initiatives are essential to our long-term operations. We expect these costs to be an ongoing obligation to achieve and maintain best in class safety performance.

Environmental costs, net of recoveries, increased $21.6 million for the year ended December 31, 2012 when compared with the same period in 2011 of which $5.0 million, net of recoveries, is related to the Line 6B crude oil release. During the year ended December 31, 2012, we recognized $170.0 million in insurance recoveries in connection with the Line 6B crude oil release compared to $335.0 million for the same period in 2011. We increased our total incident cost accrual by $55.0 million for the year ended December 31, 2012, compared to an increase of $215.0 million for the year ended December 31, 2011. An additional $8.9 million of environmental costs were recognized related to the Line 14 crude oil release on our Lakehead system near Grand Marsh, Wisconsin that occurred on July 27, 2012. We also recognized additional environmental costs in aggregate of $7.7 million related to other minor crude oil releases.

For the year ended December 31, 2011, we settled a dispute with a shipper on our Lakehead crude oil pipeline system, which we recognized in 2011, for oil measurement adjustments we had previously experienced in prior years. We recorded $52.2 million to oil measurement adjustments, which is a reduction to operating expenses for the year ended December 31, 2011. There were no such adjustments for the year ended December 31, 2012.

Power costs increased $4.0 million for the year ended December 31, 2013, compared with the same period in 2011. The increase in power costs is primarily associated with the higher volumes of crude oil transported on our Lakehead system.

 

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The increase in depreciation expense of $12.9 million for the year ended December 31, 2013 is directly attributable to the additional assets we have placed in service since the same period in 2012.

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. The National Energy Board, or NEB, estimated that total production from the WCSB averaged approximately 3.3 million Bpd in 2013 and 3 million in 2012. Meanwhile, strong production growth from the Bakken formation has increased tight oil available from North Dakota to nearly 780,000 Bpd in 2013, as compared to 600,000 Bpd in 2012. With access to growing supply from the WCSB and Bakken formation, the Lakehead system will remain an important conduit for crude oil to U.S. markets for years to come. Volumes of WCSB crude oil production currently exceed those from Iraq and Venezuela, key members of the Organization of Petroleum Exporting Countries, or OPEC.

Based on forecasted growth in Western Canadian crude oil production and completion of upgrader expansions and increased bitumen production, our Lakehead system deliveries are expected to grow beyond the 1.8 million Bpd of actual deliveries in 2013. 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, United States demand and 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 affected by periodic maintenance, refinery turnarounds and other shutdowns at producing plants that supply crude oil to, or refineries that take delivery from, our Lakehead system.

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 932,000 Bpd as of September 2013, with projections of exceeding 1 million Bpd in early 2014.

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 75% of the total Bakken crude exported from North Dakota. Rail provides some advantages to pipeline transportation alternatives, but its recent dominance in market share is considered to be primarily driven by extreme price differentials Bakken crudes received vis-à-vis Brent or other non-Cushing based oil markets. Future Enbridge pipeline expansions and enhanced market access to eastern Canadian markets and eastern PADD II are expected to decrease current crude oil price differentials. As pipeline expansion projects create more export capacity from the Bakken, other pipeline projects provide increased access to more refinery markets across the United States, and price differentials return to long term average levels, more North Dakota customers are expected to shift their volumes back to pipelines as the primary transportation option given the economies of scale and other advantages that pipeline transportation enjoy vis-à-vis rail.

 

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The table below summarizes the Partnership’s 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

   $ 2,070        2013—2014 (4)      Joint (1) 

Eastern Access Upsize—Line 6B Expansion

     365        Early 2016        Joint (1) 

U.S. Mainline Expansions

       

Line 61 (ME phase 1)

     215        Q3 2014        Joint (2) 

Line 67 (ME phase 1)

     205        Q3 2014 (3)      Joint (2) 

Chicago Area Connectivity (Line 62 twin)

     495        Late 2015        Joint (2) 

Line 61 (ME phase 2)

     1,250        Mid 2015, 2016        Joint (2) 

Line 67 (ME phase 3)

     240        2015        Joint (2) 

Line 6B 75-mile Replacement Program

     390        Q2 2013—Q1  2014 (5)      EEP   

Berthold Rail

     135        Q1 2013        EEP   

Bakken Pipeline Expansion

     300        Q1 2013        EEP   

Bakken Access Program

     100        Mid 2013        EEP   

Sandpiper Project

     2,600        Early 2016        Joint (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)

Delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.

 

(4)

As of December 31, 2013, the following projects related to the Eastern Access Projects have been put into service: (1) Line 5 and (2) Line 62 Expansion.

 

(5)

As of December 31, 2013, the Line 6B 75-mile Replacement Program has been put into service with only two 5-mile segments remaining to be put into service in Q1 2014.

 

(6)

As of November 25, 2013, the Sandpiper Project is funded 62.5% by the Partnership and 37.5% by Williston Basin Pipe Line LLC under the North Dakota Pipeline Company Amended and Restated Limited Liability Company Agreement.

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 original proposed expansion involved construction of an approximate 600-mile 24-inch diameter line from Beaver Lodge Station near Tioga, North Dakota, to the Superior, Wisconsin mainline system terminal. In September 2013, a scope modification was made to increase the twin line diameter from 24-inches to 30-inches between Clearbrook and Superior. The

 

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new line will twin the 210,000 Bpd North Dakota system mainline, which now terminates at Clearbrook Terminal, adding 225,000 Bpd of capacity on the twin line between Tioga and Clearbrook and 375,000 Bpd between Clearbrook and Superior. As a result of scope modifications, the expected capital cost increased by approximately $100 million, and the Sandpiper project is now 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, the Partnership, through its subsidiary, North Dakota Pipeline Company LLC, or NDPC, formerly known as Enbridge Pipelines (North Dakota) LLC, 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 (not to exceed $1.2 billion in aggregate). As a result of Williston funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in service date of Sandpiper targeted for early 2016.

We filed a petition with the FERC to approve recovering Sandpiper’s costs through a surcharge to the Enbridge Pipelines (North Dakota) LLC rates between Beaver Lodge and Clearbrook and a cost of service structure for rates between Clearbrook and Superior. On March 22, 2013, the FERC denied the petition on procedural grounds. We plan to re-file the petition with modifications to address the FERC’s concerns. Furthermore, in November 2013, we also announced 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. The pipeline is expected to begin service in early 2016, subject to obtaining regulatory and other approvals, as well as finalization of scope.

Eastern Access Projects

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 the Canadian provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States. One of the projects involved the expansion of the Partnership’s Line 5 light crude line between Superior, Wisconsin and Sarnia, Ontario by 50,000 Bpd. The Line 5 expansion was placed into service in May 2013. In May 2012, we and Enbridge announced further plans to expand access to Eastern markets. The projects to be pursued by the Partnership include: (1) expansion of the Spearhead North pipeline, or Line 62 expansion, between Flanagan, Illinois and the Terminal at Griffith, Indiana by adding horsepower to increase capacity from 130,000 Bpd to 235,000 Bpd; and (2) replacement of additional sections of the Partnership’s 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. Portions of the existing 30-inch diameter pipeline are being replaced with 36-inch diameter pipe. The Line 62 expansion was put into service in November 2013. The target in-service date for the remaining Line 6B Replacement project is split into two phases, with the segment between Griffith and Stockbridge expected to be completed in the first quarter of 2014 and the segment from Ortonville, Michigan to Sarnia, Ontario expected to be completed in the third quarter of 2014. These projects, including the previously discussed Line 5 and Line 62 expansion completions, will cost approximately $2.1 billion and will be 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 December 2012, the Partnership will expand the Eastern Access Projects, which will include further expansion of the Line 6B component with increasing capacity from 500,000 Bpd to 570,000 Bpd and will involve the addition of new pumps, existing station modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge, at an expected cost of approximately $365 million. This further expansion of the Line 6B component is expected to begin service in early 2016.

 

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These projects collectively referred to as the Eastern Access Projects, will cost approximately $2.4 billion. From May 2012 through June 27, 2013, the projects were jointly funded by our General Partner at 60% and the Partnership at 40%, under 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 of the Eastern Access Projects from 40% to 25%. 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 percentage points.

U.S. Mainline Expansions

In May 2012, we also announced further expansion of our mainline pipeline system, which included: (1) increasing capacity on the existing 36-inch diameter Alberta Clipper pipeline, or Line 67, between Neche, North Dakota into the Superior, Wisconsin Terminal from 450,000 Bpd to 570,000 Bpd; and (2) expanding of the existing 42-inch diameter Southern Access pipeline, or Line 61, between the Superior Terminal and the Flanagan Terminal near Pontiac, Illinois from 400,000 Bpd to 560,000 Bpd. These projects require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction, at a cost of approximately $420 million. 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, the expansions will be undertaken on a full cost-of-service basis and are expected to be available for service in the third quarter of 2014 for the initial expansion to 570,000 Bpd and 2015 for the expansion to 800,000 Bpd. It is now anticipated that it will take longer to obtain regulatory approval than planned. A number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput.

As part of the Light Oil Market Access Program announced in December 2012, the capacity of our Lakehead System between Flanagan, Illinois, and Griffith, Indiana will be expanded by constructing a 76-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. Additionally, the capacity of our Southern Access pipeline, or Line 61, will be expanded to its full 1,200,000 Bpd potential and additional tankage requirements at an estimated cost of approximately $1.25 billion. Subject to regulatory and other approvals, the expansions are expected to begin service in 2015, with additional tankage expected to be completed in 2016.

On January 4, 2013, we announced further expansion of our Alberta Clipper pipeline, or Line 67, which will add an additional 230,000 Bpd of capacity at an estimated cost of approximately $240 million. The expansion involves increased pumping horsepower, 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, the expansion is expected to be available for service in 2015.

These projects collectively referred to as the U.S. Mainline Expansions projects, will cost approximately $2.4 billion and will be undertaken on a cost-of-service basis. 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. 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 U.S. Mainline Expansions projects from 40% to 25%. Additionally, within one year of the in-service date, scheduled for 2016, the Partnership will have the option to increase its economic interest by up to 15 percentage points.

 

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Canadian Eastern Access and U.S. 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; (2) construction of a 35-mile pipeline adjacent to Enbridge’s Toledo Pipeline, originating at the Partnership’s Line 6B in Michigan to serve refineries in Michigan and Ohio; (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 9B 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; 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 light oil volumes and enhance operational flexibility. The Line 9A reversal was completed in August 2013. The 35-mile pipeline adjacent to Enbridge’s Toledo Pipeline was completed and placed into service in May 2013. Several of the outstanding projects remain subject to regulatory approval and have various targeted in-service dates through 2015. 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.

Line 6B 75-mile Replacement Program

On May 12, 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 are being completed in components, with approximately 65 miles of segments placed in service since the first quarter of 2013. The two remaining 5-mile segments in Indiana are expected to be placed in service in components in the first quarter of 2014. The replacement program has been carried out in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. The total capital for this replacement program is now estimated to cost $390 million. These costs will be recovered through our Facilities Surcharge Mechanism, or FSM, which is part of the system-wide rates of the Lakehead system.

Berthold Rail

In December 2011, we announced that we were proceeding with the Berthold Rail Project, an interim solution to shipper needs in the Bakken region. The project expands pipeline capacity into the Berthold, North Dakota Terminal by 80,000 Bpd and included the construction of a three unit-train loading facility, crude oil tankage and other terminal facilities adjacent to existing facilities. During September 2012, the first phase of terminal facilities was completed, providing capacity of 10,000 Bpd to the Berthold Terminal. The final construction of the loading facility and the crude oil tankage (Phase II) were placed into service in March 2013. The estimated cost of the Berthold Rail Project was approximately $135 million.

Bakken Pipeline Expansion

In August 2010, we announced the Bakken Project, a joint crude oil pipeline expansion project with an affiliate of Enbridge in the Bakken and Three Forks formations located in North Dakota. The Bakken Project

 

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follows our existing rights-of-way in the United States and those of Enbridge Income Fund Holdings in Canada to terminate and deliver to the Enbridge Mainline system’s terminal at Cromer, Manitoba, Canada. The United States portion of the Bakken Project expands the United States portion of the Portal Pipeline, which was reversed in 2011 in order to flow oil from Berthold to the United States border and on to Steelman, Saskatchewan, by constructing two new pumping stations in Kenaston and Lignite, North Dakota, and replacing an 11-mile segment of the existing 12-inch diameter pipeline that runs from these two locations. The project also expanded our existing terminal and station in Berthold, North Dakota. We commenced construction in July of 2011 and the Bakken Project was completed and placed into service in March 2013 providing capacity of 145,000 Bpd. This project, with the North Dakota mainline, results in a total takeaway capacity for this region of 355,000 Bpd. The United States portion of the Bakken Project had an estimated cost of approximately $300 million.

Bakken Access Program

In October 2011, we announced the Bakken Access Program, a series of projects which represents an upstream expansion that will further complement our Bakken Project, discussed above. This expansion program was placed into service in phases in mid-2013, substantially enhancing our gathering capabilities on the North Dakota system by 100,000 Bpd and increasing pipeline capacities, constructing additional storage tanks and adding truck access facilities at multiple locations in western North Dakota. The estimated cost of the Bakken Access Program remains at approximately $100 million.

Enbridge United States Gulf Coast Projects and Southern Access Extension

A key strength of the Partnership is our relationship with Enbridge. In 2011, Enbridge announced two major United States Gulf Coast market access pipeline projects, which, when completed, will pull more volume through the Partnership’s 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 Pakota, Illinois.

Flanagan South Pipeline

Enbridge’s Flanagan South Pipeline project will transport more volumes into Cushing, Oklahoma and twin its existing Spearhead pipeline, which starts at the hub in Flanagan, Illinois and delivers volumes into the Cushing hub. The 590-mile, 36-inch diameter pipeline will have an initial capacity of approximately 600,000 Bpd, and subject to regulatory and other approvals, the pipeline is expected to be in service by the third quarter of 2014. On August 23, 2013, the Sierra Club and National Wildlife Federation, the Plaintiff, 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 Protection Act. On September 5, 2013, Enbridge obtained intervener status and joined the Defendants in filing a response in opposition to the motion for preliminary injunction. The Court hearing was held on September 27, 2013, and the Plaintiff’s request for preliminary injunction was denied by the Court on November 13, 2013. A court hearing is scheduled for February 21, 2014 concerning the merits of the Complaint against the federal agencies.

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

 

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City Terminal and Distribution System that serves refineries in the Houston and Texas City areas. 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. Actual throughput in 2013 was curtailed due to constraints on third party takeaway facilities. A 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 was completed in January 2014 and should eliminate these constraints.

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 that is expected to more than double its capacity to 850,000 Bpd by mid-2014. This 30-inch diameter pipeline will follow the same route as the existing Seaway Pipeline. Included in the scope of this second line is the lateral noted above from Houston, Texas to Enterprise Product’s ECHO Terminal. Furthermore, a proposed 85-mile pipeline is expected to be built from Enterprise Product’s ECHO Terminal to the Port Arthur/Beaumont, Texas refining center to provide shippers access to the region’s heavy oil refining capabilities. The new pipeline will offer incremental capacity of 750,000 Bpd, and subject to regulatory approval, is expected to be available in mid-2014.

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. In addition, Enbridge announced two binding open seasons in 2013 to solicit commitments from shippers for capacity on the proposed pipeline. Prior to the binding open season that closed in January 2013, Enbridge had received sufficient capacity commitments from an anchor shipper to support the 24-inch pipeline. In June 2013, a second open season to solicit additional capacity commitments from shippers was announced and subsequently closed in September 2013. Enbridge received further capacity commitments through the second open season, which can be accommodated within the initial capacity planned for the pipeline. Subject to regulatory and other approvals, the project is expected to be placed into service in 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, which we refer to as 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 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 will include 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 as discussed in Note 13. Commitments and Contingencies—Lakehead Line 14 Crude Oil Release 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 from the PHMSA to remove the pressure restrictions and to return to normal operating pressures for a period of

 

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twelve months. In December 2014, PHMSA will again consider the status of the pipeline in light of information they acquire throughout 2014.

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. Our natural gas business consists of the following four systems:

 

   

Anadarko system: Approximately 3,100 miles of natural gas gathering and transportation pipelines, approximately 58 miles of NGL pipelines, nine active natural gas processing plants, three standby natural gas processing plants and one standby treating plant located in the Anadarko basin.

 

   

East Texas system: Approximately 3,900 miles of natural gas gathering and transportation pipelines, approximately 108 miles of NGL pipelines, six active natural gas processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants, eight active natural gas treating plants, three standby natural gas treating plants and one fractionation facility located in the East Texas basin.

 

   

North Texas system: Approximately 4,600 miles of natural gas gathering and transportation pipelines, approximately 60 miles of NGL pipelines, six active natural gas processing plants and one standby natural gas processing plant located in the Fort Worth basin.

 

   

Texas Express NGL system: A 35% interest in an approximately 580-mile NGL intrastate transportation mainline and a related NGL gathering system that consists of approximately 116 miles of gathering lines.

The Texas Express NGL system commenced startup operations during the fourth quarter of 2013. During startup operations, revenue recognition is delayed while the system is being filled with NGLs but operating costs are recognized. Additionally, the Texas Express NGL system operates using ship or pay contracts. These ship or pay contracts contain make-up rights provisions, which are earned when minimum volume commitments are not utilized during the contract period but are also subject to contractual expiry periods. Revenue associated with these make-up rights is deferred when more than a remote chance of future utilization exists. These factors in combination contributed to a $1.0 million equity loss for the year ended December 31, 2013, which we recognized in “Other income (expense)” on our consolidated statement of income.

 

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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, 2013, 2012, and 2011.

 

     December 31,  
     2013      2012      2011  
     (in millions)  

Operating revenues

   $ 3,867.2      $ 3,967.7      $ 5,692.5  
  

 

 

    

 

 

    

 

 

 

Cost of natural gas

     3,222.1        3,172.7        4,973.8  

Environmental costs, net of recoveries

                   (0.4

Operating and administrative

     444.3        460.1        392.9  

Depreciation and amortization

     143.1        134.8        142.6  
  

 

 

    

 

 

    

 

 

 

Operating expenses

     3,809.5        3,767.6        5,508.9  
  

 

 

    

 

 

    

 

 

 

Operating Income

   $ 57.7      $ 200.1      $ 183.6  
  

 

 

    

 

 

    

 

 

 

Operating Statistics (MMBtu/d):

        

East Texas

     1,153,000        1,266,000        1,378,000  

Anadarko(1)

     949,000        1,017,000        1,013,000  

North Texas

     317,000        330,000        337,000  
  

 

 

    

 

 

    

 

 

 

Total

     2,419,000        2,613,000        2,728,000  
  

 

 

    

 

 

    

 

 

 

NGL Production (Bpd)

     88,236        97,428        87,376  
  

 

 

    

 

 

    

 

 

 

 

(1) 

Average daily volumes for the years ended December 31, 2013, 2012 and 2011 include 280,000 MMBtu/d, 255,000 MMBtu/d, and 251,000 MMBtu/d, respectively, of volumes associated with our Elk City system.

We recognize revenue upon delivery of natural gas and NGLs to customers, when services are rendered, pricing is determinable and collectability is reasonably assured. We generate revenues and segment gross margin principally under the following types of arrangements:

Equity Investment in Joint Venture

Our natural gas and NGLs business includes our 35% aggregate interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties, representing a 580-mile NGL intrastate transportation pipeline and a related NGL gathering system. We use the equity method of accounting for our 35% joint venture interest in the Texas Express NGL system as a result of our ability to significantly influence the operating activities, but insufficient ability to control these activities without the participation of a majority of the other members.

Fee-Based Arrangements

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

 

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Commodity-Based Arrangements

We also generate revenue and segment gross margin under other types of service arrangements with customers. These arrangements expose us to commodity price risk, which we mitigate to a substantial degree with the use of derivative financial instruments to hedge open positions in these commodities. We hedge a significant amount of our exposure to commodity price risk to support the stability of our cash flows. We provide additional information in Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk and Note 15. Derivative Financial Instruments and Hedging Activities of our consolidated financial statements in Item 8. Financial Statements and Supplementary Data of this report about the derivative activities we use to mitigate our exposure to commodity price risk.

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

 

   

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

 

   

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

 

   

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

 

   

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

Under the terms of each of our commodity-based service contracts, we retain natural gas and NGLs as our compensation for providing these customers with our services. As of December 31, 2013, we are exposed to fluctuations in commodity prices in the near term on approximately 35% to 40% of the natural gas, NGLs and condensate we expect to receive as compensation for our services. Due to this unhedged commodity price exposure, our segment gross margin, representing revenue less cost of natural gas, generally increases when the prices of these commodities are rising and generally decreases when the prices are declining. As a result of entering into these derivative instruments, we have largely fixed the amount of cash that we will pay and receive in the future when we sell the residue gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate. Many of the derivative financial instruments we use do not qualify for

 

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hedge accounting. As a result, we record the changes in fair value of the derivative instruments that do not qualify for hedge accounting in our operating results. This accounting treatment produces non-cash gains and losses in our reported operating results that can be significant during periods when the commodity price environment is volatile.

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 $142.4 million, as compared with the year ended December 31, 2012. The most significant area affected was Natural Gas gross margin, representing revenue less cost of natural gas, which decreased $149.9 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.

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 cost of natural gas 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.

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 on December 6, 2013 and is expected to be back to full capacity in February 2014. 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.

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,

 

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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.

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 cost of natural gas to permit the timely preparation of our consolidated financial statements. As a result, each month we record a true-up of the prior month’s estimate to equal the prior month’s actual data. Refer to Item 8. Critical Accounting Policies and Estimates for additional information regarding the estimation of our revenues and our cost of natural gas.

Operating income of our Natural Gas segment experienced non-cash, mark-to-market net losses of $4.5 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. We use the non-qualifying commodity derivatives to economically hedge a portion of the natural gas, NGLs and condensate resulting from the operating activities of our natural gas business.

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.

Operating and administrative costs of our Natural Gas segment decreased $15.8 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. See Trucking and NGL Marketing Business Accounting Matters for additional discussion;

 

   

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.

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

The gross margin of our Natural Gas segment for the year ended December 31, 2012 increased by $76.3 million from the year ended December 31, 2011 due to higher NGL production partially offset by lower commodity prices and natural gas volumes, as well as other factors described below.

 

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For the year ended December 31, 2012, prices for natural gas and NGLs declined significantly from the year ended December 31, 2011. Average natural gas prices declined approximately 31% per MMBtu based upon the NYMEX Henry Hub pricing index, for the year ended December 31, 2012, when compared to the year ended December 31, 2011. NGLs declined approximately 30% and 28% per composite barrel, for the year ended December 31, 2012 as compared to the year ended December 31, 2011, based upon the Conway and Mont Belvieu pricing hubs, respectively.

Gross margin derived from keep-whole earnings for the year ended December 31, 2012 increased $49.2 million from the year ended December 31, 2011. The increase in keep-whole earnings was attributable to paying natural gas producers, during the prior year, for liquids we were unable to recover due to gas volumes increasing faster than our available capacity on our Anadarko system. For the year ended December 31, 2012, the capacity condition was relieved due to the completion of the Allison processing plant in November 2011 and additional third party NGL takeaway capacity.

Gross margin for the year ended December 31, 2012, when compared to the year ended December 31, 2011, increased approximately $33.0 million due to the correction of accounting misstatements and other errors during the year ended December 31, 2011. In early 2012, an internal and an independent investigation identified intentional accounting misstatements and other errors by on-site management at our wholly-owned trucking and NGL marketing subsidiary over a period of several years. Following further investigation and determination we recorded the cumulative aggregate amount of the misstatements and other errors at December 31, 2011 as a reduction to the operating income of our Natural Gas segment. For additional discussion see Trucking and NGL Marketing Business Accounting Matters. There were no such adjustments for accounting misstatements or other accounting errors during the year ended December 31, 2012.

Also, during 2011, our volumes were negatively impacted due to uncharacteristically cold weather and freezing precipitation in February that moved through Oklahoma and north Texas with temperatures dropping below freezing for extended periods. These conditions resulted in significant mechanical issues with our producers’ equipment and impacted their ability to flow natural gas. Producers shut in substantial volumes during this period, which reduced the average daily volumes on our systems by approximately 56,000 MMBtu/d. Additionally, mechanical problems on two of our plants required that they be taken out of service for extended periods during the first quarter of 2011 to correct these conditions. The adverse weather conditions and plant downtime had an approximate $13.0 million negative impact to the gross margin of our Natural Gas segment for the year ended December 31, 2011.

Gross margin for the year ended December 31, 2012, increased $13.0 million, when compared to the year ended December 31, 2011, due to fee-based contracts on our East Texas, Anadarko, and Oklahoma systems. The increase in fee-based operating income was due to several factors including: (1) lower customer wellhead operating pressures resulting in higher fees to transport their natural gas; (2) changes to our customer contracts resulting in higher fees; and (3) additional volumes from our Haynesville expansion.

Gross margin also increased $11.2 million, for the year ended December 31, 2012 when compared to the year ended December 31, 2011, related to higher NGL recoveries due to increased efficiencies on our Anadarko system from the completion of our Allison plant and higher NGL content in the processing gas stream.

Additionally, gross margin from our condensate marketing business for the year ended December 31, 2012 increased approximately $10.8 million, from the year ended December 31, 2011, due to higher realized margins from enhancements of facilities that were placed into service during 2012.

The gross margin of our Natural Gas segment experienced non-cash, mark-to-market net losses of $11.5 million from December 31, 2011 to December 31, 2012 mostly due to the maturity of certain hedging agreements. These maturities were partially offset by changes in the average forward prices of natural gas, NGLs and condensate. The average forward and daily prices for natural gas and NGLs decreased for the year ended December 31, 2012, compared to the year ended December 31, 2011.

 

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Operating and administrative costs of our Natural Gas segment were $67.2 million higher for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily due to the following:

 

   

Increased workforce related costs and other allocated expenses of $26.0 million primarily due to programs and initiatives focused on renewing our focus on safety, operations and systems integrity in addition to the completion of the Allison plant and other assets being placed into service during late 2011;

 

   

Increased supporting costs of $10.6 million related to maintenance, supplies and other outside services also associated with additional assets being placed into service during late 2011;

 

   

Increased costs of $7.5 million for the investigation of accounting misstatements at our trucking and NGL marketing subsidiary with no similar costs during the same period in 2011. See Trucking and NGL Marketing Business Accounting Matters for additional discussion;

 

   

Increased pipeline integrity costs of $7.2 million as part of the operational risk management plan to ensure our systems are safe and to maintain our existing pipelines; and

 

   

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

Depreciation and amortization expense for our Natural Gas segment decreased $7.8 million, for the year ended December 31, 2012 compared with the year ended December 31, 2011, primarily due to a revision in depreciation rates for the Anadarko, North Texas and East Texas systems which became effective on July 1, 2011. The revision resulted in a decrease of approximately $17.0 million in depreciation expense for the year ended December 31, 2012, when compared to the year ended December 31, 2011. This decrease was offset with an increase in depreciation expense associated with additional assets that were put in service during late 2011.

Trucking and NGL Marketing Business Accounting Matters

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 of several years. We refer to the improper recognition of product purchases as the “accounting misstatements” and the improper recognition of product sales as “accounting errors” in the discussions which follow. The “accounting misstatements” were facilitated by conduct of the local management responsible for operating the subsidiary, whereby entries were made to modify the amounts reported for cost of goods sold included in “Cost of natural gas,” and “Accrued purchases” for the purposes of creating the appearance that the subsidiary had achieved its budget. During the performance of our review of the “accounting misstatements,” we identified other unrelated “accounting errors” associated with the recognition of sales resulting in the misstatement of “Operating revenue,” “Accrued receivables” and “Inventory,” during each accounting period. The “accounting misstatements,” and “accounting errors,” which include overstatements, understatements and other errors, occurred over a period from at least 2005 through 2011. Our net cash provided by operating activities was not affected by the accounting misstatements during these periods.

For the year ended December 31, 2010, the cumulative aggregate amount of the “accounting misstatements” and “accounting errors” was approximately $33.0 million. During 2011, local management of the trucking and NGL marketing subsidiary recorded entries totaling approximately $15.0 million as increases to cost of goods sold included in “Cost of natural gas” and decreases to “Operating revenue” that reduced the cumulative aggregate amount to $18.0 million at December 31, 2011. Following further investigation and determination that the previously unrecorded amounts were not material to the current or any prior period financial statements, we recorded the cumulative aggregate amount of $18.0 million, representing the “accounting misstatements” and “accounting errors,” at December 31, 2011 as a reduction to the “Operating income” of our Natural Gas segment to correct these “accounting misstatements” and “accounting errors.” As a result, the “Operating income” of our

 

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Natural Gas segment for the year ended December 31, 2011 was $33.0 million less than what we would have reported had the “accounting misstatements” and “accounting errors” been recognized in the year ended December 31, 2010. The $33.0 million is comprised of the $15.0 million of adjustments recorded by local management of the trucking and NGL marketing subsidiary during 2011 and the $18.0 million correction we recorded at December 31, 2011.

Future Prospects for Natural Gas

We intend to expand our natural gas gathering and processing services through 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.

The table below summarizes the Partnership’s commercially secured projects for the Natural Gas segment, which we have recently placed into service or expect to place into service in future periods. Following MEP’s initial public offering in November 2013, the below projects are now funded by the Partnership and MEP based on their proportionate ownership percentages in Midcoast Operating:

 

Project

   Estimated
Capital Costs
     In-service Date      Funding  
     (in millions)                

Ajax Cryogenic Processing Plant

   $ 230        Q3 2013         EEP   

Texas Express NGL system

   $ 400        Q4 2013         Joint (2) 

Beckville Cryogenic Processing Plant

   $ 145         Early 2015         Joint (1) 

 

(1) 

Following the Offering in November 2013, Beckville is now funded by EEP and MEP based on their proportionate ownership percentages in Midcoast Operating, which is currently 61% and 39%, respectively.

 

(2)

We own a 35% joint venture interest in the Texas Express NGL system. Estimated capital costs represent 35% of the total projected costs associated with constructing both the mainline and the gathering system.

Ajax Cryogenic Processing Plant

We expect development of the Granite Wash play in the Texas Panhandle and western Oklahoma to continue due to the prolific nature of the wells, current market prices for NGLs and crude oil and the application of horizontal drilling and fracturing technology to the formation. In order to accommodate the expected natural gas production growth from the Granite Wash play, we began commissioning the operations of a cryogenic processing plant and related facilities 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 provide necessary capacity to accommodate the anticipated volume growth within our Anadarko system. The total cost of constructing the Ajax processing plant and related facilities was approximately $230 million. The Ajax processing plant increases the total processing capacity of our Anadarko system by approximately 150 million cubic feet per day, or MMcf/d, to approximately 1,150 MMcf/d and also increases the system’s condensate stabilization capacity by approximately 2,000 Bpd. The Ajax processing plant is capable of producing approximately 15,000 barrels per day, or Bpd, of NGLs now that the Texas Express NGL pipeline, which we refer to as the mainline, was completed and put into operation during the fourth quarter of 2013 as discussed below.

Texas Express NGL System

On October 31, 2013, we, Enterprise Product Partners L.P., or Enterprise, Anadarko Petroleum Corporation, or Anadarko, and DCP Midstream Partners, LP, or DCP Midstream, announced the start of service on the Texas

 

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Express NGL system, which consists of two separate joint ventures with third parties to design and construct a new NGL pipeline, or mainline, and NGL gathering system. The joint venture ownership of the mainline portion of the Texas Express NGL system is owned 35% by Enterprise, 35% by us, 20% by Anadarko and 10% by DCP Midstream. The joint venture ownership of the new NGL gathering system is owned 45% by Enterprise, 35% by us and 20% by Anadarko. Enterprise constructed and serves as the operator of the mainline, while we constructed and operate the new gathering system.

The Texas Express NGL pipeline originates near Skellytown, Texas in the Texas Panhandle and extends approximately 580-miles to NGL fractionation and storage facilities in the Mont Belvieu area on the Texas Gulf Coast. The mainline has an initial capacity of approximately 280,000 Bpd and is expandable to approximately 400,000 Bpd with additional pump stations on the system. There are currently capacity reservations on the mainline that, when fully phased in, will total approximately 250,000 Bpd. The new NGL gathering system initially consists of approximately 116-miles of gathering lines that connect the mainline to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma and to Barnett Shale processing plants in North Texas. The gathering system is currently expected to include 270-miles of gathering lines by 2019. Volumes from the Rockies, Permian Basin and Mid-Continent regions will be delivered to the Texas Express NGL system utilizing Enterprise’s existing Mid-America Pipeline assets between the Conway hub and Enterprise’s Hobbs NGL fractionation facility in Gaines County, Texas. In addition, volumes from and to the Denver-Julesburg Basin in Weld County, Colorado are able to access the Texas Express NGL system through the connecting Front Range Pipeline which is being constructed by Enterprise, DCP Midstream and Anadarko.

We expect that the Texas Express NGL system will serve as a link between growing supply sources of NGLs in the Anadarko and Permian basins and the Mid-Continent and Rockies regions of the United States and the primary demand markets on the U.S. Gulf Coast. We expect our total contributions to be approximately $400 million for the construction of the Texas Express NGL system.

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 and has been a steady producer of natural gas for decades. Production from this play typically contains two to three gallons of NGLs per Mcf 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. In the third quarter of 2013, we initiated construction activities at our Beckville processing plant and the related facilities on our East Texas system. We estimate the cost of constructing the plant to be approximately $145 million and expect it to commence service in early 2015.

 

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Marketing

The following table sets forth the operating results of our Marketing segment assets for the periods presented:

 

     December 31,  
     2013     2012     2011  
     (in millions)  

Operating revenues

   $     1,730.0     $     1,392.6     $     2,131.9  
  

 

 

   

 

 

   

 

 

 

Cost of natural gas

     1,726.8       1,397.4       2,126.3  

Operating and administrative

     5.5       6.6       6.3  

Depreciation and amortization

                 0.1  
  

 

 

   

 

 

   

 

 

 

Operating expenses

     1,732.3       1,404.0       2,132.7  
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ (2.3   $ (11.4   $ (0.8
  

 

 

   

 

 

   

 

 

 

Our Marketing business derives a majority of its operating income from selling natural gas received from producers on our Natural Gas segment 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.

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

In addition to the market access provided by our company-owned intrastate natural gas pipelines, our Marketing business also contracts for firm transportation capacity on third-party interstate and intrastate pipelines to allow access to additional markets. To mitigate the demand charges associated with these transportation agreements, 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 our Marketing business 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 Marketing segment.

In addition to natural gas transport capacity and the associated basis swaps, we contract for storage to assist with balancing natural gas supply and end use market sales. 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

 

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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.

Natural gas purchased and sold by our Marketing 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 Marketing business 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 storage, interruptible storage or parking and lending services. These various contract structures are used to mitigate risk associated with sales and purchase contracts, and to take advantage of price differential opportunities.

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

The operating results of our Marketing segment for the year ended December 31, 2013 increased by $9.1 million when compared to the year ended December 31, 2012.

The increase in operating results of our Marketing business, was primarily due to higher natural gas prices during the year ended December 31, 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, our marketing operations 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 of our Marketing segment, 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 current 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.

Included in the operating results of our Marketing segment for the year ended December 31, 2013 were non-cash, mark-to-market net losses of $2.8 million as compared with $3.1 million of non-cash, mark-to-market net losses for the year ended December 31, 2012 associated with derivative instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance. The decrease in non-cash, mark-to-market net losses for the year ended December 31, 2013, as compared to the year ended December 31, 2012, was primarily attributed to the realization of financial instruments used to hedge our transportation positions. The net losses associated with these derivative instruments resulted from the widening difference between the forward natural gas purchase and sales prices between market centers, which negatively impacted the values of the derivative financial instruments we use to hedge our transportation positions.

 

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

The operating results of our Marketing segment for the year ended December 31, 2012 decreased by $10.6 million when compared to the year ended December 31, 2011 primarily due to the continued erosion of natural gas prices and associated differentials.

Natural gas prices for the year ended December 31, 2012 were lower and relatively stable as compared to the year ended December 31, 2011. This price environment led to limited opportunities to benefit from significant price differentials between market centers, which negatively impacted the Marketing segment operating results by $7.3 million for the year ended December 31, 2012, as compared to the year ended December 31, 2011.

Included in the operating results of our Marketing segment for the year ended December 31, 2012 were non-cash, mark-to-market net losses of $3.1 million as compared with $0.7 million of non-cash, mark-to-market net gains for the year ended December 31, 2011 associated with derivative instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance. This increase in non-cash, mark-to-market net losses for the year ended December 31, 2012, as compared to the year ended December 31, 2011, was primarily attributed to the realization of financial instruments used to hedge our storage and transportation positions. The net losses associated with our storage derivative instruments resulted from the widening difference between the natural gas injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas was sold from storage.

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,  
     2013     2012     2011  
     (in millions)  

Operating Results:

      

General and administrative expenses

   $ 7.6     $ 2.3     $ 2.2  
  

 

 

   

 

 

   

 

 

 

Operating loss

     (7.6     (2.3     (2.2

Interest expense

         320.4           345.0           320.6  

Allowance for equity used during construction

     43.1       11.2        

Other income (expense)

     16.0       (1.2     6.5  

Income tax expense

     18.7       8.1       5.5  
  

 

 

   

 

 

   

 

 

 

Net loss

     (287.6     (345.4     (321.8

Net income attributable to Noncontrolling interest

     88.3       57.0       53.2  

Series 1 preferred unit distributions

     58.2              

Accretion of discount on Series 1 preferred units

     9.2              
  

 

 

   

 

 

   

 

 

 

Net loss attributable to general and limited partners

   $ (443.3   $ (402.4   $ (375.0
  

 

 

   

 

 

   

 

 

 

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

The increase in our net loss in 2013 was mostly attributed to the issuance of Series 1 Preferred Units by the Partnership to its General Partner in May of 2013. The Partnership attributed approximately $58.2 million of earnings to the preferred unitholders in 2013 as compared to the same period in 2012.

 

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Offsetting the increase in Series 1 preferred unit distributions was a decrease in interest expense from $320.4 million for the year ended December 31, 2013, compared with $345.0 million for 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.

Income tax expense increased $10.6 million for the year ended 2013 compared to the same period in 2012, primarily due to a $12.4 million of income tax expense recognized for the three month period ended June 30, 2013 related to a new law passed in the State of Texas. See Note 11. Income Taxes for further discussion regarding this new tax laws. Our interest cost for the years ended December 31, 2013 and 2012 is detailed below:

 

     December 31,  
     2013     2012  
     (in millions)  

Interest expense

   $     320.4     $     345.0  

Interest capitalized

     51.7       36.3  
  

 

 

   

 

 

 

Interest incurred

   $ 372.1     $ 381.3  
  

 

 

   

 

 

 

Interest paid

   $ 342.3     $ 352.1  
  

 

 

   

 

 

 

Weighted average interest rate

     6.2 %      6.4 % 

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. Our income tax expense of $18.7 million, for the year ended December 31, 2013, is computed by applying a 0.5% Texas state income tax rate to modified gross margin. 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.

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

The increase in our net loss in 2012 was mostly attributable to the increase in interest expense as compared to the same period in 2011. Interest expense was $345.0 million for the year ended December 31, 2012 compared with $320.6 million for the corresponding period in 2011. This increase in interest expense is primarily the result of a higher weighted average outstanding debt balance during the year ended December 31, 2012 as compared with the same period in 2011. The increased weighted average outstanding debt balance was primarily a result of the issuance and sale in September 2011 of $600 million of our 4.20% senior unsecured notes due 2021 and an additional $150 million of our 5.50% senior unsecured notes due 2040. These additions were partially offset by a lower commercial paper balance, the maturity of $100 million of our 7.9% senior unsecured notes in November 2012 and the maturity of our First Mortgage Notes in December 2011.

We are exposed to interest rate risk associated with changes in interest rates on our variable rate debt. The interest rates on our variable rate debt are determined at the time of each borrowing or interest rate reset based upon a posted London Interbank Offered Rate, or LIBOR, for the period of borrowing or interest rate reset, plus applicable margin. In order to mitigate the negative effect that increasing interest rates can have on our cash flows, we have purchased interest rate swaps with a total notional value of $4.9 billion as of December 31, 2012. The changes in fair value of the interest rate swaps that do not qualify for hedge accounting are recorded as corresponding increases or decreases in “Interest expense” on our consolidated statements of income. For the year ended December 31, 2012 interest expense increased due to recognition of unrealized losses for hedge ineffectiveness of approximately $20.8 million associated with interest rate hedges that were originally set to mature in December 2012. However, in December 2012, these hedges were amended to extend the maturity date to December 2013 to better reflect the expected timing of future debt issuances.

 

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Offsetting the increase in interest expense is the $22.7 million increase in interest capitalized to our capital projects for year ended December 31, 2012 as compared to the same period in 2011. This is due to higher amounts spent on our capital projects in 2012 that have not yet been placed into service. Our interest cost for the years ended December 31, 2012 and 2011 is detailed below:

 

     December 31,  
     2012     2011  
     (in millions)  

Interest expense

   $     345.0     $     320.6  

Interest capitalized

     36.3       13.6  
  

 

 

   

 

 

 

Interest incurred

   $ 381.3     $ 334.2  
  

 

 

   

 

 

 

Interest paid

   $ 352.1     $ 314.3  
  

 

 

   

 

 

 

Weighted average interest rate

     6.4 %      6.4 % 

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 and Michigan impose taxes that are based upon many, but not all, items included in net income. Our income tax expense of $8.1 million, for the year ended December 31, 2012 is computed by applying a 0.5% Texas state income tax rate to modified gross margin. For 2011, we had an income tax expense of $5.5 million, which we computed by applying a 0.5% Texas state income tax rate to modified gross margin, and a 0.2% Michigan state income tax rate to net income and modified gross receipts. The $5.5 million represents $6.6 million of expense related to Texas and $1.1 million of benefit related to Michigan. The Michigan benefit is related to the Michigan Business Tax being repealed in 2011. Due to this change in Michigan tax legislation, we no longer are required to pay Michigan income taxes beginning in 2012 as discussed in Note 16. Income Taxes.

Other Matters

Alberta Clipper Pipeline Joint Funding Arrangement

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. The Alberta Clipper Pipeline was mechanically complete in March 2010 and was ready for service on April 1, 2010. In connection with the joint funding arrangement, we allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $52.6 million, $53.9 million and $53.2 million to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline for the years ended December 31, 2013, 2012 and 2011, respectively. We have presented the amounts we allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Joint Funding Arrangement for Eastern Access Projects

In May 2012, we amended and restated partnership agreement of the OLP to establish an additional series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. From May 2012 through June 27, 2013, our General Partner indirectly owned 60% 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

 

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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 $609.2 million and $347.9 million to the OLP for the year ended December 31, 2013 and 2012, respectively to fund its equity portion of the construction costs associated with the Eastern Access Projects.

We allocated earnings from the Eastern Access Projects in the amount of $32.1 million to our General Partner for its 60% ownership of the EA interest for the year ended December 31, 2013. We allocated earnings derived from the Eastern Access Projects in the amount of $3.4 million to our General Partner for the year ended 2012. We have presented this amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

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 $159.9 million and $3.0 million to the OLP for the year ended December 31, 2013 and year ended 2012, respectively to fund its equity portion of the construction costs associated with the U.S. Mainline Expansion Projects.

We allocated earnings from the Mainline Expansion Projects in the amount of $0.3 million to our General Partner for its ownership of the ME interest for the year ended December 31, 2013. We have presented this amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

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 billion credit agreement with Bank of America, as administrative agent, and the lenders party thereto, which we refer to as the Credit Facility, and our $1.2 billion credit agreement with JPMorgan Chase Bank as administrative agent, and the lenders party thereto, 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 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.

 

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As set forth in the following table, we had approximately $2.6 billion of liquidity available to us at December 31, 2013 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 Lines 6A and 6B.

 

     (in millions)  

Cash and cash equivalents

   $ 164.8  

Total credit available under Credit Facilities

     3,175.0  

Less: Amounts outstanding under Credit Facilities

     335.0  

Principal amount of commercial paper issuances

     300.0  

Letters of credit outstanding

     76.7  
  

 

 

 

Total

   $      2,628.1  
  

 

 

 

General

Our primary operating cash requirements consist of normal operating expenses, core maintenance expenditures, distributions to our partners and payments associated with our risk management activities. We expect to fund our current and future short-term cash requirements for these items from our operating cash flows supplemented as necessary by issuances of commercial paper and borrowings 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 its Board of Directors around the commercial terms of such a sale. When we have attractive growth opportunities in excess of our own capital raising capabilities, the General Partner has 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, 2013, we had a working capital deficit of approximately $1,316.6 million and approximately $2.6 billion of liquidity to meet our ongoing operational, investing and financing needs as of December 31, 2013 as shown above, as well as the funding requirements associated with the environmental costs resulting from the crude oil releases on Lines 6A and 6B.

Capital Resources

Equity and Debt Securities

Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private equity and credit markets to obtain the capital necessary to fund these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our internal growth projects and targeted acquisitions will require additional permanent capital and

 

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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. 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 7, 2013, the Partnership entered into the Series 1 Preferred Unit Purchase Agreement, or Purchase Agreement, with our General Partner pursuant to which we issued and sold 48,000,000 of our Series 1 Preferred Units, representing limited partner interests in the Partnership, for aggregate proceeds of approximately $1.2 billion. The closing of the transactions contemplated by the Purchase Agreement occurred on May 8, 2013.

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 the Partnership 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 the Partnership. The quarterly cash distribution for the three month period ended June 30, 2013 was prorated from May 8, 2013. 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. The impact of the beneficial conversion feature is also included in earnings per unit for the year ended December 31, 2013.

Proceeds from the Preferred Unit issuance were used by the Partnership 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.

 

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Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit issuances for the years ended December 31, 2012 and 2011. There were no similar issuances for the year ended December 31, 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  
  

 

 

       

 

 

    

 

 

    

 

 

 

2011

              

December(4)

     9,775,000      $ 30.85      $ 292.0      $ 6.1      $ 298.1  

September(4)

     8,000,000      $ 28.20        218.3        4.6        222.9  

July(4)

     8,050,000      $ 30.00        233.7        4.9        238.6  
  

 

 

       

 

 

    

 

 

    

 

 

 

2011 Totals

     25,825,000         $ 744.0      $ 15.6      $ 759.6  
  

 

 

       

 

 

    

 

 

    

 

 

 

 

(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.

 

(4) 

The proceeds from the December 2011 and September 2011 offerings were used to fund a portion of our capital expansion projects, while the proceeds from the July 2011 offering were used to repay a portion of our outstanding commercial paper and fund a portion of our capital expansion projects.

Equity Distribution Agreement

In June 2010, we entered into the Equity Distribution Agreement, or EDA, for the issuance and sale from time to time of our Class A common units up to an aggregate amount of $150.0 million. The EDA allowed us to issue and sell our Class A common units at prices we deemed appropriate for our Class A common units. Under the EDA, we sold 2,118,025 Class A common units, representing 4,236,050 units after giving effect to a two-for-one split of our Class A common units that became effective on April 21, 2011, for aggregate gross proceeds of $124.8 million, of which $64.5 million are gross proceeds received in 2011. No further sales were made under that agreement. On May 27, 2011, we de-registered the remaining aggregate $25.2 million of Class A common units that were registered for sale under the initial EDA and remained unsold as of that date.

On May 27, 2011, the Partnership entered into the Amended and Restated Equity Distribution Agreement, or Amended EDA, for the issuance and sale from time to time of our Class A common units up to an aggregate amount of $500.0 million from the execution date of the agreement through May 20, 2014. The units issued under the Amended EDA are in addition to the units offered and sold under the EDA. The issuance and sale of our Class A common units, pursuant to the Amended EDA, may be conducted on any day that is a trading day for the New York Stock Exchange, or NYSE.

 

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The following table presents the net proceeds from our Class A common unit issuances, pursuant to the initial EDA and the Amended EDA, during the year ended December 31, 2011. There were no similar issuances for the years ended December 31, 2013 or 2012:

 

Issuance Date

   Number of
Class A
common units
Issued
     Average
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)  

2011

              

January 1 to March 31(3)

     1,773,448      $ 32.26      $             55.9      $                 1.2      $             57.1  

April 1 to May 26(3)

     225,200      $ 32.16        7.0        0.1        7.1  

May 27 to June 30(4)

     333,794      $ 30.30        9.9        0.2        10.1  

July 1 to September 30(4)

     751,766      $ 28.38        20.8        0.4        21.2  
  

 

 

       

 

 

    

 

 

    

 

 

 

2011 Totals

     3,084,208         $ 93.6      $ 1.9      $ 95.5  
  

 

 

       

 

 

    

 

 

    

 

 

 

 

(1) 

Net of commissions and issuance costs of $2.2 million.

 

(2) 

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

 

(3) 

Units and unit price adjusted for the April 2011 stock split.

 

(4) 

Units issued under the Amended EDA.

Midcoast Energy Partner, L.P.

On November 13, 2013, MEP, a subsidiary of EEP, completed its initial public offering (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. We intend to sell additional interests in our natural gas assets, held through Midcoast Operating, to MEP and use