10-K 1 d464561d10k.htm FORM 10-K Form 10-K
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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, 2012

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.  x

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

 

Large Accelerated Filer  x   Accelerated Filer  ¨
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, 2012, was $5,893,123,201.

As of February 14, 2013 the registrant has 254,208,428 Class A common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page  
 

PART I

  

Item 1.

 

Business

     1   

Item 1A.

 

Risk Factors

     35   

Item 2.

 

Properties

     52   

Item 3.

 

Legal Proceedings

     52   
 

PART II

  

Item 5.

 

Market for Registrant’s Common Equity and Related Unitholder Matters

     53   

Item 6.

 

Selected Financial Data

     54   

Item 7.

 

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

     57   

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

     108   

Item 8.

 

Financial Statements and Supplementary Data

     118   

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     190   

Item 9A.

 

Controls and Procedures

     190   

Item 9B.

 

Other Information

     192   
 

PART III

  

Item 10.

 

Directors, Executive Officers and Corporate Governance

     193   

Item 11.

 

Executive Compensation

     201   

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management

     232   

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

     234   

Item 14.

 

Principal Accountant Fees and Services

     244   
 

PART IV

  

Item 15.

 

Exhibits and Financial Statement Schedules

     244   

Signatures

     245   

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. 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 Lines 6A and 6B; (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, or 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

AIDC

   Allowance for interest during 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

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

ERCB

   Energy Resource Conservation Board, a successor regulatory body to the Alberta Energy Utility Board

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

 

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ISDA®

   International Swaps and Derivatives Association, Inc.

Lakehead system

   United States portion of the liquid petroleum mainline system

LIBOR

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

Light Oil Market Access

Program

  

 

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

M3

   Cubic meters of liquid = 6.2898105 Bbl

Mainline Expansion Joint

Funding Agreement

  

 

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

Mainline system

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

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

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

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

PADD III

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

 

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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, 2012. The ownership percentages referred to below illustrate the relationships between us, 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, 2012, our portfolio of assets included the following:

 

   

Approximately 6,500 miles of crude oil gathering and transportation lines and 35 million barrels, or MMBbl, of crude oil storage and terminaling capacity;

 

   

Natural gas gathering and transportation lines totaling approximately 11,400 miles;

 

   

Eight active natural gas treating plants and 25 active natural gas processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants, with a total aggregate capacity of approximately 3,105 million cubic feet per day, or MMcf/d, and plants we may idle from time to time based on current volumes;

 

   

Trucks, trailers and railcars for transporting natural gas liquids, or NGLs, crude oil and carbon dioxide; 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.

BUSINESS STRATEGY

Our primary objective is to provide stable and sustainable cash distributions to our unitholders, 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 the 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.

 

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  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.

Liquids

The map below presents the locations of our current Liquids systems’ assets and projects being constructed. This map depicts some 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.

 

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In 2012, 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 2012 from the United States Department of Energy’s Energy Information Administration, or EIA, Canada supplied approximately 2.4 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, which we refer to as CAPP, in their June 2012 forecast of future production from the Alberta Oil Sands, continued to expect steady growth in supply during the next 18 years with an additional 3.4 million Bpd of incremental supply available 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 Alberta Oil Sands to our existing and new markets.

North Dakota, Montana and Saskatchewan, Canada have continued to experience tremendous growth in the development of crude oil, natural gas, and NGLs from the Bakken and Three Forks formations. The latest data released in August 2012 by the EIA showed 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 that the proved reserve base is substantially higher than what the EIA published.

Along with Enbridge, we are actively working with our customers to develop 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 growing production of North Dakota and western Canada light oil production. Together, our existing and future plans advance our vision of being North America’s first choice for liquids deliveries.

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. One of the projects involves the expansion of our Line 5 light crude line between Superior, Wisconsin and Sarnia, Ontario by 50,000 Bpd. Complementing the Line 5 expansion, Enbridge announced plans to reverse portions of its Line 9A and Line 9B in western Ontario to permit crude oil movements eastbound from Sarnia to Westover, Ontario and as far as Montreal, Quebec. The Line 5 expansion is targeted to be in service during the first quarter of 2013, and the Line 9A and Line 9B reversal is targeted to be in service in late 2013 and in 2014, respectively. In May 2012, we and Enbridge announced further plans to expand access to Eastern markets. The projects pursued by the Partnership include: (1) expansion of the Spearhead North pipeline, or Line 62, between Flanagan, Illinois and the Terminal at Griffith, Indiana by adding horsepower to increase capacity from 130,000 Bpd to 235,000 Bpd, and an additional 330,000 barrel crude oil tank at Griffith; and (2) replacement of additional sections of the Partnership’s Line 6B in Indiana and Michigan to increase capacity from 240,000 Bpd to 500,000 Bpd. Portions of the existing 30-inch diameter pipeline will be replaced with 36-inch diameter pipe. Subject to customary regulatory approvals, these projects are expected to be placed in-service during 2013 and 2014. These projects are collectively referred to as the Eastern Access Projects.

In December 2012, we and Enbridge also announced 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. Additionally, 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

 

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initial capacity of 570,000 Bpd. Additionally, the capacity of our Southern Access pipeline, or Line 61, will be expanded to its full 1,200,000 Bpd potential with additional tankage requirements. Some of the overall expansion is expected to begin service in mid-2015, with additional tankage expected to be completed in 2016.

In North Dakota, oil production levels rose to approximately 733,000 Bpd by December 2012 an approximate 37% increase since December 2011. Capitalizing on this growth, we continue to develop options to access key refinery markets for the Bakken region. Our Bakken Pipeline Expansion, Bakken Access Program and Berthold Rail Project are all projects that will allow Bakken crude oil further access to markets. For further discussion on these projects see BUSINESS SEGMENTS—North Dakota System in this Item.

A key strength of the Partnership is our relationship with Enbridge. Enbridge has announced two major United States Gulf Coast market access pipeline projects and their Southern Access Extension Project, which when completed will pull more volume through the Lakehead system.

 

   

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 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 is 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 which serves refineries in Houston and Texas City areas. In the second quarter of 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 to approximately 400,000 Bpd, depending upon the mix of light and heavy grades of crude oil. In addition, in March 2012, plans were announced to construct an 85-mile pipeline from Enterprise Product’s ECHO Terminal to a Port Arthur/Beaumont, Texas refining center, which will offer incremental capacity of 560,000 Bpd and is expected to be available in mid-2014.

 

   

Southern Access Extension—In December 2012, Enbridge announced a binding open season to solicit commitments from shippers for capacity on the proposed Southern Access Extension pipeline to be constructed, owned and operated by a U.S. subsidiary. The pipeline will transport crude oil from Pontiac, Illinois at Enbridge’s Flanagan Terminal where it will receive crude oil from the Lakehead System to Patoka, Illinois. The 165-mile, 24-inch diameter, crude oil pipeline is expected to be placed into service in 2015, subject to regulatory approval.

 

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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. 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 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.

 

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The long term prospects in our core areas remain favorable, primarily as a result of technological advancements that have enhanced production of natural gas and NGLs from tight sand and shale formations. The reserves and resource potential in all three of our operating basins is substantial. The current price environment has producers focusing 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 incenting 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 118 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 seven 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 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 1,200,000 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 3.4 million Bpd to over 5 million Bpd by 2030. With this

 

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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 1,900 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 61 pump station locations with a total of approximately 900,000 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 in excess of 55 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 2012, approximately 42 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 3.1 million Bpd in 2012 and 2.8 million in 2011. Meanwhile, strong production growth from the Bakken formation has increased tight oil available from North Dakota to nearly 570,000 Bpd in 2012, as compared to 380,000 Bpd in 2011. 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 169 billion barrels according to the Energy Resources Conservation Board, or ERCB. Additionally, remaining established conventional oil reserves in Western Canada were estimated to be approximately 3.2 billion barrels at the end of 2012. Canada’s total combined conventional and oil sands estimated proved reserves of approximately 175 billion barrels at the end of 2011 compares with Saudi Arabia’s estimated proved reserves of approximately 265 billion barrels.

According to CAPP, an estimated total $262 billion Canadian dollars, or CAD, has been spent on oil sands development from 1997 through 2010. 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 2012 Growth Forecast estimates that the future production from the Alberta Oil Sands is expected to grow steadily during the next 18 years, with an additional 3.4 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

 

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Steam Assisted Gravity Drainage, or SAGD, and mining facilities. The 2012 delivered production of four major Alberta Oil Sands producers is detailed as follows:

 

  1. Synthetic production from one of Suncor Energy Inc.’s, or Suncor’s, upgraders with a capacity of approximately 350,000 Bpd, averaged approximately 324,000 Bpd in 2012, which was 19,000 Bpd higher than in 2011, and consistent with Suncor’s annual target. Suncor completed its Firebag Stage 3 expansion in the first quarter of 2012 thereby allowing the targeted increase in the production of bitumen of approximately 62,500 Bpd, over the following 18 month period. Since Firebag Stage 3 is now complete, Suncor intends to shift its focus to Firebag Stage 4, which has the same expected production capacity and has an expected in-service date in early 2013. In 2011, Suncor announced its strategic partnership with Total E&P Canada, which will enable both companies to jointly develop the Joslyn and Fort Hills oil sands mining projects, as well as resume construction on the Voyageur upgrader.

 

  2. Syncrude Canada Ltd.’s, or Syncrude’s, synthetic production in 2012 averaged 286,500 Bpd, matching production levels in 2011. 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 will 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.

 

  3. In September 2012, Cenovus began production at Phase D of its Christina Lake Project. Phase D is expected to yield an additional 40,000 Bpd of production and brings the project’s production capacity up to 98,800 Bpd at the end of 2012. Construction of Phase E is on schedule for a fourth quarter 2013 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 300,000 Bpd.

 

  4. Imperial Oil’s Kearl Lake oil sands project is expected to start up in early 2013. Initial production will ramp up to approximately 110,000 Bpd. First production had originally been slated for fourth quarter 2012, however was pushed back due to weather delays. 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 open-pit 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 Suncor’s North Steepbank Extension, Athabasca Oil Corporation’s Hangingstone and Canadian Natural Resources’ Kirby South. Based on the CAPP Production forecast, unblended bitumen production is expected to increase by roughly 264,000 Bpd by the end of 2013 and then increase by an additional 163,000 Bpd by the end of 2014.

Although the crude oil and liquid petroleum delivered through our Lakehead system originates primarily in oilfields in Western Canada, our Lakehead system also receives approximately 8% 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.

In the coming years, Bakken production is expected to become a major component of the Unites States domestic supply mix. Conservative estimates from the United States Energy Information Administration expects production to reach 800,000 Bpd by 2015 and over 1 million Bpd by 2021.

 

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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 average approximately 2 million Bpd in 2013, which is 200,000 Bpd higher than the 1.8 million Bpd of actual deliveries in 2012. 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, 2012 demand for crude oil in PADD II averaged 3.5 million Bpd, an increase of 78,000 Bpd from 2011. At the same time, production of crude oil within PADD II increased by 264,000 Bpd to 1.1 million Bpd.

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) and the United States Gulf Coast (PADD III). 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 2012, the latest data available shows that PADD II total demand was 3.5 million Bpd while it produced only 1.1 million Bpd and thus imported 2.4 million Bpd from Canada and other regions of the United States. The 2012 data indicates PADD II imported approximately 1.7 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 2012 were approximately 90,000 Bpd higher than delivery volumes for 2011. Total deliveries from our Lakehead system averaged just under 1.8 million Bpd in 2012, meeting approximately 88% of the refinery capacity in the greater Chicago area; 80% of the Minnesota refinery capacity; and 80% of Ontario refinery demand in 2012.

Considering all of the transportation systems that transport crude oil out of Canada, the Mainline system transported over half of all Canadian crude oil imports to the United States in 2012. The remaining production was transported by systems serving the British Columbia, PADD II, PADD IV and PADD V markets. There are a number of smaller competing pipelines located in PADD IV that transport Canadian crude oil into production facilities within the United States. However, the production facilities located within the Rocky Mountain states have significantly less refining capacities in relation to the facilities we serve that are located within the Midwest region of the United States.

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 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 an emerging 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

 

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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. The Northern Gateway Pipeline has an expected in-service date in the 2018 timeframe, depending on the length of the regulatory review process. 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 proposed 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 extension 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. The construction of the extension 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, which may be received as early as March 2013.

 

   

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 expected to be 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 660,000 Bpd. A final decision on this expansion is expected by the end of March 2013.

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

 

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The following table sets forth average deliveries per day and barrel miles of our Lakehead system for each of the periods presented.

 

     2012      2011      2010      2009      2008  
     (thousands of Bpd)  

United States

              

Light crude oil

     521        473        458        467        388  

Medium and heavy crude oil

     879        850        841        834        876  

NGL

     5        4        3        4        3  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total United States

     1,405        1,327        1,302        1,305        1,267  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Ontario

              

Light crude oil

     228        220        223        197        183  

Medium and heavy crude oil

     85        84        57        73        80  

NGL

     72        69        73        75        90  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Ontario

     385        373        353        345        353  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Deliveries

     1,790        1,700        1,655        1,650        1,620  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Barrel miles (billions per year)

     480        450        439        423        432  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Mid-Continent system

Our Mid-Continent system, which we have owned since 2004, is located within PADD II and is comprised of our Ozark pipeline and storage terminals at Cushing, Oklahoma and El Dorado, Kansas. Our Mid-Continent system includes over 435 miles of crude oil pipelines and 20.5 million barrels of crude oil storage capacity. 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 105 individual storage tanks ranging in size from 55,000 to 575,000 barrels with three new tanks under various stages of construction that will add 936,000 barrels of incremental shell capacity for service during 2013. Of the 20.5 million barrels of storage shell capacity on our Mid-Continent system, the Cushing terminal accounts for 19.2 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 2012, approximately 54 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 223,000 Bpd for 2012 and 226,000 Bpd for 2011.

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 2012, PADD II imported 2.5 million Bpd from outside of the PADD II region. The 2012 data indicates PADD II imported approximately 1.7 million Bpd of crude oil from Canada, a majority 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 gap between local supply and demand for crude oil in PADD II to continue to widen, encouraging imports of crude oil from Canada, PADD III and foreign sources.

 

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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 is increasing 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 transportation system servicing the Williston basin in North Dakota and Montana, which includes the Bakken and Three Forks formations. The crude oil gathering pipelines of our North Dakota system collect crude oil from points near, approximately, 4,600 producing wells in North Dakota and Montana. Most deliveries from our North Dakota system are made at Clearbrook to our Lakehead system and to a third-party pipeline system. Our North Dakota system includes approximately 240 miles of crude oil gathering lines connected to a transportation line that is approximately 730 miles long, with a capacity of approximately 210,000 Bpd at the end of 2012. Our North Dakota system also has 21 pump stations, one delivery station and 10 storage facilities with an aggregate working storage capacity of approximately 891,000 barrels.

The following are Bakken Projects that will allow Bakken crude oil to access our markets:

 

   

Bakken Pipeline Expansion—In August 2010, to further solidify our position as the primary transportation provider for crude oil production from the Bakken and Three Forks formations located in the states of Montana and North Dakota and the Canadian provinces of Saskatchewan and Manitoba., we announced the Bakken Pipeline Expansion project, or the Bakken Project, a joint crude oil pipeline expansion project with Enbridge Income Fund Holdings Inc., a partially-owned subsidiary of Enbridge. Upon completion in the first quarter of 2013, the Bakken Project will provide capacity of 145,000 Bpd. This project, with the North Dakota mainline, will result in a total takeaway capacity for this region of 355,000 Bpd. Of the 145,000 Bpd, 100,000 Bpd is in the form of firm commitments with multiple shippers who have committed to the project. For the first year 85,000 Bpd of these commitments we will receive 75% of their shipper-pay payments which are made regardless of shipment of volumes, and 100% thereafter. The term of these contracts are 5 or 10 years with the majority at 10 years.

 

   

Bakken Access Program—In October 2011, we announced the Bakken Access Program, a series of projects which represent an upstream expansion that will further complement our Bakken Project, as

 

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discussed above. This access program will substantially enhance our gathering capabilities on the North Dakota system by 100,000 Bpd. This program, expected to be in-service by mid-2013, involves increasing pipeline capacities, construction of additional storage tanks and addition of truck access facilities at multiple locations in western North Dakota.

 

   

Berthold Rail Project—In December 2011, we announced the Berthold Rail Project that will provide an alternative transportation solution to shipper needs in the Bakken region. The project will expand capacity into the Berthold terminal by 80,000 Bpd and includes 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 an additional capacity of 10,000 Bpd to the Berthold Terminal. The loading facility and the crude oil tankage are expected to be placed into service during the first quarter of 2013.

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 the 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 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 has seen increased production levels up to 572,000 Bpd as of December 2012, an approximate 52% increase in production levels since December 2011. 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.    Competitors of our North Dakota system include 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 some existing rail loading facilities.

In recent years rail transportation has also emerged as an alternative method of shipping crude to market. While historically rail has not been considered an economically viable transportation solution for producers looking for market access, price spreads driven by limited transportation infrastructure to key markets and the lead time required to get new pipelines into service has opened up opportunities for the railway industry. These transportation and market access constraints have resulted in large crude oil price differences between the North Dakota supply basin and refining market centers. As a result, crude oil producers have begun moving increasing amounts of oil by rail which has increased competition to our North Dakota system and decreased our system utilization. We expect this competition to decrease our 2013 volumes, compared to our volumes for the year ended December 31, 2012. 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. Crude oil producers are expected to then shift their volumes back to pipelines as the primary transportation option since pipeline transportation costs are significantly less costly than rail. We continue to solidify our long term position in the Bakken formation, and the announcement of several expansion projects should increase our available capacity within this region.

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.

 

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Natural Gas Segment

We own and operate natural gas gathering, treating, processing and transportation systems as well as trucking, rail and liquids marketing operations. We purchase and gather natural gas from the wellhead and deliver it to plants for treating and/or processing and to intrastate or interstate pipelines for transmission to wholesale customers such as power plants, industrial customers and local distribution companies.

Natural gas treating potentially involves the removal of hydrogen sulfide, carbon dioxide, water and other substances from raw natural gas so that it will meet the standards for pipeline transportation. Natural gas processing involves the separation of raw natural gas into residue gas and NGLs. Residue gas is the processed natural gas that ultimately is consumed by end users. NGLs separated from the raw natural gas are either sold and transported as NGL raw mix or further separated through a process known as fractionation and sold as their individual components, including ethane, propane, butanes and natural gasoline. At December 31, 2012, we had eight active treating plants and 25 active processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants. We may idle some of these plants from time to time based on current volumes. Our treating facilities have a combined capacity that approximates 1,090 MMcf/d while the combined capacity of our processing facilities approximates 2,015 MMcf/d, including 350 MMcf/d provided by the HCDP plants.

Our natural gas business consists of the following systems:

 

   

East Texas system: Includes approximately 3,900 miles of natural gas gathering and transportation pipelines, eight natural gas treating plants and five natural gas processing plants, including two HCDP plants.

 

   

Anadarko system: Consists of approximately 2,900 miles of natural gas gathering and transportation pipelines in southwest Oklahoma and the Texas panhandle and 11 natural gas processing plants, which includes the assets we obtained in September 2010 when we acquired the Elk City system.

 

   

North Texas system: Includes approximately 4,600 miles of natural gas gathering pipelines and nine natural gas processing plants located in the Fort Worth basin.

Customers.    Our natural gas pipeline systems serve customers predominantly in the United States Gulf Coast region and include both purchasers and producers of natural gas. Purchasers are comprised of large users of natural gas, such as power plants, industrial facilities, local distribution companies, large consumers seeking an alternative to their local distribution company, and shippers of natural gas, such as natural gas producers and marketers, including our Marketing business. Producers served by our systems consist of small, medium and large independent operators and large integrated energy companies. We sell NGLs resulting from our processing activities to a variety of customers ranging from large petrochemical and refining companies to small regional retail propane distributors.

Supply and Demand.    Demand for our gathering, treating and processing 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 2012, overall natural gas prices were at levels below the prices experienced in recent years due to excess supplies of natural gas in the United States. While NGL prices were down from prior years, they remained above historical averages most of the year. Ethane and propane prices declined throughout the current year, but the heavier components of NGLs were sustained throughout the 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 natural gas assets are in basins

 

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that have the opportunity to grow in an improved pricing environment. All three of our natural gas systems exist in regions that have shale or tight sands formations where horizontal fracturing technology can be utilized to increase production from the natural gas wells.

Our East Texas system is primarily located in the East Texas basin. The Bossier Trend, which is located on the western side of our East Texas system within the East Texas basin, has been a driver of growth on our East Texas system for the past several years. Production in the Bossier Trend grew from 650 MMcf/d in 1997 to a peak of 2,400 MMcf/d in March of 2009. However, with the decline in natural gas prices, the Bossier Trend has seen a decrease in development with production falling to 1,400 MMcf/d as of August 2012. Low natural gas prices have also lead to decreased drilling activity in and around the Haynesville Shale. The Haynesville Shale is a formation that runs from western Louisiana into eastern Texas, and is one of the largest natural gas discoveries in the United States. Due to lower levels of producer activity, in light of weak natural gas prices, we have deferred portions of our previously announced Haynesville natural gas expansion pending increases in drilling activity. Consistent with trends observed elsewhere, an increase in activity has been noted in the East Texas basin related to horizontal drilling of the Cotton Valley formation which has a high content of NGLs and condensate.

A substantial portion of natural gas on our North Texas system is produced in the Barnett Shale area within the Fort Worth basin conglomerate. The Fort Worth basin conglomerate is a mature zone that is experiencing slow production decline. In contrast, the Barnett Shale area became one of the more active natural gas plays in North America. While abundant natural gas reserves have been known to exist in the Barnett Shale area since the early 1980s, recent technological advances in fracturing the shale formation allows commercial production of these natural gas reserves. Based on the latest information available for 2012, Barnett Shale production has risen from approximately from 110 MMcf/d in 1999 to approximately 5,700 MMcf/d by August 2012. We anticipate that throughput on the North Texas system will be steady in each of the next several years as a result of modest Barnett Shale development due to low natural gas prices. This is a result of producers deploying their resources to other natural gas shale plays with higher liquids content.

Our Anadarko system is located within the Anadarko basin and has experienced considerable growth as a result of the rapid development of the Granite Wash play in Hemphill and Wheeler counties in Texas. Favorable pricing for NGLs relative to the lower prices for natural gas has encouraged producers to increase production in the Granite Wash formation due to the high content of NGLs and condensate present in the natural gas stream. Rig counts have increased steadily since late 2009 with an increased emphasis by producers to use horizontal drilling and multistage hydraulic fracturing technologies. Exploitation of the Granite Wash formation by our customers is primarily due to the successful application of horizontal drilling and fracturing technologies.

In response to the increased supply of natural gas and NGLs and the increased demand for our services in the Anadarko region, we acquired the Elk City system in September 2010. The Elk City system includes one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 MMcf/d, and a combined current NGL production capability of approximately 30,000 Bpd, enabling us to process greater volumes of natural gas resulting from the increased production in the Granite Wash formation. This acquisition enhanced the processing capacity and expansion capability of our Anadarko system. In an effort to further alleviate the capacity constraints resulting from the increasing supplies of natural gas in the areas served by our Anadarko system, we constructed a cryogenic processing plant, which we refer to as the Allison Plant. The Allison Plant was placed into service in November 2011 and is intended to accommodate the increase of horizontal drilling activity that exists in the Granite Wash formation. With the completion of additional third party NGL takeaway capacity to the Allison Plant in April 2012, we can now fully utilize its capacity. In August 2011, we announced plans to construct an additional processing plant and other facilities, including compression and gathering infrastructure, on our Anadarko system, anticipated to be in service in mid-2013 which we refer to as our Ajax Plant. The Allison and Ajax plants, when operational, will increase the total processing capacity on our Anadarko system to approximately 1,200 MMcf/d. Several of our competitors have announced gathering and processing expansions in the Anadarko region which are in various stages of completion. We expect our large geographic footprint, competitively priced services and favorable producer drilling economics will enable us to keep our facilities well utilized for the foreseeable future.

 

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Other potential expansions may arise as more producers begin further developing the Granite Wash, Barnett Shale, Haynesville Shale and other areas in the basins served by our systems and commit for additional capacity. We will opportunistically evaluate strategic prospects to further expand the service capabilities of our existing systems.

Results of our Natural Gas business depend upon the drilling activities of natural gas producers in the areas we serve. We anticipate that volume growth will be modest or flat until forward natural gas prices improve. We expect that natural gas production will continue to rise in areas with high liquids content gas and to decline in our dry gas basins due to low natural gas prices.

In the second half of 2013, a joint venture among us, Enterprise Products, DCP Midstream and Anadarko Petroleum Corporation, or Anadarko, to design and construct a new NGL pipeline and two new NGL gathering systems, collectively referred to as the Texas Express Pipeline project, or TEP will begin service. The pipeline originates at Skellytown, Texas and extends approximately 580 miles to NGL fractionation and storage facilities in Mont Belvieu, Texas and will have an initial capacity of approximately 280,000 Bpd. TEP will assist us in fulfilling our strategic objective of expanding our presence in the natural gas and NGL value chain and provide us with a new source of strong and stable cash flow. For further discussion of TEP see also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Future Prospects for Natural Gas.

Competition.    Competition from other pipeline companies is significant in all the markets we serve. Competitors of our gathering, treating and processing systems include interstate and intrastate pipelines or their affiliates and other midstream businesses that gather, treat, process and market natural gas or NGLs. 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 natural gas producers and owners 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 the sour natural gas systems, such as a component of our East Texas system, competition is more limited in certain locations due to the infrastructure required to treat sour natural gas.

Competition for customers in the marketing of residue natural gas is based primarily upon the price of the delivered natural gas, the services offered by the seller and the reliability of the seller in making deliveries. Residue natural gas also competes on a price basis with alternative fuels such as crude oil and coal, especially for customers that have the capability of using these alternative fuels, and on the basis of local environmental considerations. Competition in the marketing of NGLs comes from other NGL marketing companies, producers, traders, chemical companies and other asset owners.

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 pipelines. 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 pipeline systems. 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. These operations include the transportation of NGLs, crude oil and other products by pipeline, truck and railcar from wellheads and treating, processing and fractionation facilities to wholesale customers, such as distributors, refiners and

 

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chemical facilities. In addition, our trucking and NGL marketing operations resell these products. A key component of our business is ensuring market access for the liquids extracted at our processing facilities. On average, this accounts for approximately 40% of the volumes marketed or transported by our trucking and NGL marketing business and is a major source of its growth in this area.

Our services are provided using trucks, trailers and rail cars, pipeline capacity, fractionation agreements, product treating and handling equipment. Our trucking operations transport NGLs, condensate and crude oil from our processing facilities and from third party producers to our United States Gulf Coast customers. In October 2010, we acquired the assets of a common carrier trucking company for $10.3 million to meet the growing supply of NGLs, condensate and crude oil, as well as to capitalize on the opportunity to better serve our United States Gulf Coast customers. As a result of the acquisition, our fleet expanded in excess of 250 trucks and in excess of 300 trailers, as of December 31, 2012.

NGL Marketers.    Most of the customers of our trucking and NGL marketing operations are wholesale customers, such as refineries and propane distributors. Our trucking and NGL marketing operations also market products to wholesale customers such as petrochemical plants.

Supply and Demand.    Supply is sourced from a variety of areas in the United States Gulf Coast, with a significant amount of the NGL volume coming from our own gathering and processing facilities. Crude oil and natural gas prices and production levels affect the supply of these products. The demand for our services is affected by the demand for NGLs and crude oil by large industrial refineries and similar customers in the regions served by this business.

Competition.    Our trucking and NGL marketing operations have a number of competitors, including other trucking and railcar operations, pipelines, and, to a lesser extent, marine transportation and alternative fuels. In addition, the marketing activities of our trucking and NGL marketing operations have numerous competitors, including marketers of all types and sizes, affiliates of pipelines and independent aggregators.

Marketing Segment

Our Marketing segment’s primary objectives are to maximize the value of the natural gas purchased by our gathering systems and the throughput on our gathering and intrastate wholesale customer pipelines and to mitigate financial risk. To achieve this objective, our Marketing segment transacts with various counterparties to provide natural gas supply, transportation, balancing, storage and sales services.

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

 

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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.

REGULATION

Regulation by the FERC of Interstate Common Carrier 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

 

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

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

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

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

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.

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 ¶

 

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

Accounting for Pipeline Assessment Costs

In June 2005, the FERC issued an order in Docket 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 beginning at page 118 of this annual report on Form 10-K for additional discussion.

Regulation by the FERC 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 intrastate pipeline activities of Enbridge to the jurisdiction of the Texas Railroad Commission via its Informal Complaint Process.

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. In addition, under FERC regulations we are subject to market manipulation and transparency rules. This includes the public posting of certain contract information pursuant to FERC Order No. 735 et al.

 

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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-A. Additionally, several of our gathering systems fall under the definition of “major non-interstate pipeline.” These systems were previously subject to FERC Order No. 720 et al., however on October 24, 2011 the U.S. Court of Appeals for the Fifth Circuit issued an Opinion vacating the FERC rule (RM08-2) promulgated by Order Nos. 720 and 720-A, which required major intrastate pipelines to post their system’s flow information. The Fifth Circuit entered its final mandate on December 30, 2011. In keeping with that mandate, Enbridge ceased posting of capacity and flow information for its major intrastate pipelines on January 3, 2012.

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. Also, some states have, or are considering providing, greater regulatory scrutiny over the commercial regulation of the natural gas gathering business. 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. Certain regulations implemented by the FERC in recent years could increase the cost of transportation service on certain petroleum products pipelines. However, we do not believe that these regulations affect us any differently than other marketers of these products.

Other Regulation

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

 

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Tariffs and Transportation Rate Cases

Lakehead system

Under the published rate tariff as of December 31, 2012 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

   $         0.3471      $         0.3665      $         0.4008  

To Superior, Wisconsin

   $ 0.7121      $ 0.7590      $ 0.8410  

To Chicago, Illinois area

   $ 1.5308      $ 1.6449      $ 1.8451  

To Marysville, Michigan area

   $ 1.8400      $ 1.9789      $ 2.2225  

To Buffalo, New York area

   $ 1.8849      $ 2.0275      $ 2.2770  

Clearbrook, Minnesota to Chicago

   $ 1.3742      $ 1.4688      $ 1.6348  

 

(1) 

Pursuant to FERC Tariff No. 43.10.0 as filed with the FERC and with an effective date of July 1, 2012 (converted from $/m3 to $/Bbl).

The transportation rates as of December 31, 2012 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 us 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 surcharge, which is added to the base transportation rates, is a cost-of-service based calculation that is trued-up annually (usually in April) for actual costs and throughput from the previous calendar year and is not subject to indexing. The initial term of the SEP II portion of the Settlement Agreement was for 15 years, beginning in 1999 and expiring December 31, 2013.

 

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Terrace Surcharge

Under the 1998 Settlement Agreement, the Lakehead system implemented a transportation rate surcharge for the Terrace expansion program which is referred to as the Terrace Surcharge, of approximately $0.013 per barrel for light crude oil from the Canadian border to Chicago and will remain at this level through 2013, when the Terrace Surcharge ends. In addition to the Terrace Surcharge, included in the tariff agreement are the Terrace Schedule B and C adjustments. The Schedule B adjustment to the Terrace Surcharge is required if the current multi-pipeline cost of equity exceeds the 1998 multi-pipeline rate of return by plus or minus 200 basis points. In 2012, since the current multi-pipeline rate of return plus or minus 200 basis points was less than the 1998 multi-pipeline rate of return, an adjustment to the Terrace Surcharge was made. The Schedule C adjustment to the Terrace Surcharge is required when Terrace Phase III facilities are in service and the annual actual average pumping exiting Clearbrook is less than 225,000 cubic meters, or m3, per day. In the 2012 Surcharge Filing, the actual annual average pumping for 2011 was slightly below the volume threshold. However, no adjustment was made to the Terrace Surcharge.

Facilities Surcharge

In June 2004, the FERC approved an Offer of Settlement in Docket No. OR04-2-000 between the Lakehead system and CAPP, for a facilities surcharge to be implemented separately from and incrementally to the then-existing surcharges in its tariff rates, which we refer to as the Facilities Surcharge. Enbridge Energy, Limited Partnership, 107 FERC ¶ 61,336 (2004). The Facilities Surcharge was intended to be utilized to include additional projects negotiated and agreed upon between the Lakehead system 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;

 

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  (7) Clearbrook Manifold; and

 

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

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.

The Line 6B Pipeline Replacement and Dig Program Project, or Project 15 above, consists of two parts:

 

  a. The first is a pipeline replacement which is designed to recover an estimated $288 million in capital cost, including contingency, escalation and Allowance for funds used during construction, or AFUDC. The project includes the replacement of five 5-mile sections of pipe downstream of the pump station between Griffith and Stockbridge and one 50-mile segment of pipe downstream of Stockbridge.

 

  b. The second is a 2012 dig program which permits Enbridge to recover the average capital cost per dig undertaken in 2012 for digs in excess of 100 digs per year. These costs are to be included in the Facilities Surcharge for 2012. A dig program involves rehabilitation of sections of pipeline to extend its useful life, and lessen the potential for a pipeline release.

The Griffith Terminal Expansion Project, or Project 16 above, is designed to recover an estimated $21.8 million in capital cost, including contingency and market escalation.

Enbridge Energy and CAPP have agreed that the costs associated with Line 6B Replacement and Dig Program Project and Griffith Terminal Expansion Project should be recovered through the FSM. Since the filing was uncontested, the Commission accepted the Supplement to the Settlement on the grounds that it is fair, reasonable, and in the public interest.

 

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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.

The Flanagan Tank Replacement Project, or Project 17 above, has an overall estimated capital cost of $38.7 million and includes the replacement of two out of service tanks with two new tanks.

The Eastern Access Phase 1 Mainline Expansion, or Project 18 above, has an overall estimated capital cost of $1.5 billion which is a decrease from the filing of $1.7 billion, including contingency, market escalation, and AFUDC. It has three main components:

 

  a. The Line 5 Mainline Expansion will provide an additional 50,000 Bpd of light crude oil capacity on Line 5 from Superior, Wisconsin to Sarnia, Ontario, at an estimated capital cost of $101.8 million, which is an increase from the filing of $95.3 million. The quoted annual capacity of Line 5 is 490,000 Bpd;

 

  b. The Line 62 Spearhead North Expansion involves adding two new pump stations and one new 333,000-barrel tank in Flanagan, Illinois, which will provide an additional 105,000 Bpd of capacity on Line 62 between Flanagan, Illinois and Hartsdale, Indiana, at an estimated capital cost of $315 million, which is an increase from the filing of $280 million; and

 

  c. The Line 6B Replacement involves installation of 160 miles of 36-inch pipeline from Griffith, Indiana to Stockbridge, Michigan. This upsized pipeline will provide an additional 260,000 Bpd of capacity on that line segment at an estimated capital cost of $1.1 billion, which is a decrease from the filing of $1.3 billion.

As of December 31, 2012, the Facilities Surcharge was $0.5712 per barrel for light crude oil movements from the International border near Neche, North Dakota to Chicago, Illinois.

Other Tariff and Transportation Rate Cases

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. The damage claim portion of the PBF complaint is redacted, so an estimate of damages cannot be provided. 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. PBF filed an answer to Enbridge on June 26, 2012, and Enbridge filed a further reply on July 3, 2012, re-stating that this is a long held practice and to order it to be changed would have negative consequences on other shippers. On August 9, 2012, FERC set the matter for hearing, first ordering a settlement process. The first settlement meeting was September 25, 2012. The second settlement meeting was held on November 7, 2012, at which time Enbridge and PBF expressed that they were unable to settle the matter. On November 16, 2012, the settlement judge issued an order terminating the settlement process and appointing an Administrative Law Judge for the hearing. The case is on a Track III schedule, meaning the hearing will commence within 42 weeks (i.e., by September 6, 2013), and the initial decision must be issued within 63 weeks (i.e., by January 2014).

 

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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. High Prairie filed its answer on June 20, 2012, alleging that Enbridge misstated the facts and the law. Enbridge filed its response on July 5, 2012, reiterating that the law is clear and that High Prairie is trying to obfuscate that fact by focusing on its version of the facts. High Prairie filed a further response on July 13, 2012. A FERC decision has not yet been issued.

On October 22, 2012, Enbridge filed FERC Tariff No. 41.3.0 canceling FERC Tariff No. 41.2.0. The proposed tariff revises Enbridge’s downstream nomination verification procedure in Enbridge’s Rules and Regulations tariff by eliminating a frozen 24-month historical period and substituting it with the capability of the 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 establishing a technical conference. The first technical conference session will likely be held at FERC on February 6, 2013.

International Joint Tariff

FERC Tariff No. 45.1.0, issued May 31, 2012, revised the International Joint Tariff, or IJT, effective July 1, 2012, by increasing the transportation tolls by 2.447% and including a credit for the Line 5 Claim of $0.263 per cubic meter for movements of heavy crude from Hardisty, Alberta to the U.S. border near Gretna, Manitoba. 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 comprised of pipeline, terminaling and storage infrastructure located in the Mid-Continent region of the United States. Specifically, the system originates in Cushing and offers transportation service to Wood River, and other Mid-Continent system facilities, local area refineries and to other interconnected non-affiliated pipelines. The transportation rate for light crude oil from Cushing to principal delivery points are set forth below:

 

     Published
Transportation
Rate Per Barrel
 

To Wood River

   $       0.5948 (1) 

Transfer charge at Cushing

   $ 0.1305 (2) 

 

(1) 

Pursuant to FERC Tariff No. 48.2.0 as filed with the FERC on May 31, 2012, with an effective date of July 1, 2012.

 

(2) 

Pursuant to FERC Tariff No. 51.2.0 as filed with the FERC on May 31, 2012, with an effective date of July 1, 2012.

The transportation rates as of December 31, 2012, 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.

 

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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 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 January 4, 2012, the North Dakota system filed an amendment to its Rules and Regulations in order to enhance and clarify the quality specifications contained within the tariff to be effective February 4, 2012. The tariff established new volumetric penalties for Sulfur, API Gravity, and Basic Sediment and Water. In response to a protest that was filed, the Commission rejected the tariff on the basis that Enbridge North Dakota had not provided evidence to support the need for and the levels of the proposed penalties.

On February 29, 2012, notice was provided by the North Dakota system of the extension of the temporary, partial embargo for deliveries to Clearbrook, Minnesota from the Berthold, North Dakota receipt point due to vibration issues that had occurred at Berthold. Initial notice of the temporary, partial embargo was provided on October 28, 2011.

On March 1, 2012, the North Dakota system filed to provide notice of the lifting of the temporary, partial embargo, to establish an initial rate for a gathering service at Alexander and to incorporate an updated calculation of the surcharges on the two previously approved Phase 5 and 6 expansions. The tariff went into effect April 1, 2012.

On May 31, 2012, the North Dakota system amended its Rules and Regulations tariff by implementing a revised mid-month call for crude process. The tariff went into effect July 1, 2012.

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

 

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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 August 31, 2012, the North Dakota system filed to establish initial gathering and truck unloading services and charges at Alexander, North Dakota and Tioga, North Dakota. The two $0.10/Bbl interconnection rates resulted from shippers’ requests for pipeline interconnections with two shippers to facilitate receipts into Enbridge North Dakota at Alexander and Tioga. The tariff became effective October 1, 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 will result in a substantial increase in the capacity available to transport Bakken crude both to and through Clearbrook, North Dakota to Superior, Wisconsin. The terms of the proposal include, among other things, the addition of a cost of service rate surcharge to the existing rates to Clearbrook, and a new cost of service tariff rate from Clearbrook to Superior. 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. At the time of this filing our Petition for Declaratory Order process is ongoing.

In the first quarter of 2013, the Bakken Project will go into service and will transport 145,000 Bpd of Bakken crude from the North Dakota system to Cromer, Manitoba, Canada.

 

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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, Newberg, and Sherwood, North Dakota to Clearbrook, Minnesota

   $ 1.2265  

From Berthold, North Dakota to Clearbrook, Minnesota or the International boundary near Portal, North Dakota

   $ 1.2265  

From Stanley, North Dakota to Clearbrook or the International boundary near Portal, North Dakota

   $ 1.2265  

From Grenora, North Dakota to Clearbrook, Minnesota or the International boundary near Portal, North Dakota

   $ 1.3718  

From Flat Lake and Reserve, Montana to Clearbrook, Minnesota or the International boundary near Portal, North Dakota

   $ 1.4039  

From Tioga, North Dakota to Clearbrook, Minnesota or the International boundary near Portal, North Dakota

   $ 1.2584  

From Trenton, North Dakota to Clearbrook, Minnesota or the International boundary near Portal, North Dakota

   $ 1.8893  

From Alexander, North Dakota to Clearbrook, Minnesota or the International boundary near Portal, North Dakota

   $ 1.9374  

From Reserve, Montana to Tioga, North Dakota

   $ 0.7104  

From Trenton, North Dakota to Tioga, North Dakota

   $ 0.9533  

From Alexander, North Dakota to Tioga, North Dakota

   $ 1.0013  

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

   $ 0.2500  

From Tioga, North Dakota to Stanley, North Dakota

   $ 0.9411  

From Grenora, North Dakota to Stanley, North Dakota

   $ 1.0455  

From Reserve, Montana to Stanley, North Dakota

   $ 1.0751  

From Trenton, North Dakota to Stanley, North Dakota

   $ 1.5502  

From Alexander, North Dakota to Stanley, North Dakota

   $ 1.5945  

Gathering from Newburg, North Dakota or Flat Lake, Montana

   $ 0.8233  

 

(1) 

Pursuant to FERC Tariff No. 72.20.0 as filed with the FERC on August 31, 2012, with an effective date of October 1, 2012.

 

(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

 

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under all modes of transportation, including interstate and intrastate pipelines. Periodically the PSA has been reauthorized and amended, imposing new mandates on the regulator to promulgate new regulations and imposing direct mandates on operators of pipelines.

On December 29, 2006, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, 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. For example, the Marshall release resulted in a record $3.7 million civil penalty

 

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and multiple recommendations from the resultant NTSB investigation. 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 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

 

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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 published and became effective on August 16, 2012. The compliance dates range from October 15, 2012, to October 15, 2013, dependent on the affected equipment. 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.

 

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EMPLOYEES

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

INSURANCE

Our operations are subject to many hazards inherent in the liquid petroleum and natural gas gathering, treating, processing and transportation industry. 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, 2013. 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 another Enbridge subsidiary.

The coverage limits and deductible amounts at December 31, 2012 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 $ 660.0       $ 0.1  

Pollution liability

   Up to $ 660.0       $ 5.0  

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, referred to as 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, 2012, we have provided $231.8 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, 2012, we would have been required to provide additional letters of credit in the aggregate amount of $45.4 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, 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;

 

   

Fluctuations in our working capital needs; and

 

   

The cost of acquisitions.

 

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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 and 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;

 

   

Economic conditions;

 

   

Supply disruptions;

 

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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;

 

   

Environmental impact;

 

   

Reputation management;

 

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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 being heard have been towards 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 factor.

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, Minnesota, Chicago, Detroit, Michigan, Toledo, Buffalo, New York, 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.

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

 

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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 and NGLs in connection with our marketing activities. Our exposure to commodity price volatility is inherent to our natural gas and NGL purchase and resale activities, in addition to our natural gas processing activities. 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 fees we derive from 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 financial performance.

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.

 

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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, 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

 

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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.

In June of 2009, the United States House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009, which was then placed on the United States Senate legislative calendar for consideration. However, the Senate never acted on the legislation during the 111th Congress, which ended at the end of 2010. The U.S Environmental Protection Agency (EPA) is working on regulations to limit greenhouse gas emissions within its existing statutory authority under the Clean Air Act. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. Further, on April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal CAA. In July 2008, the EPA released an Advanced Notice of Proposed Rulemaking regarding possible future regulation of greenhouse gas emissions under the CAA and other potential methods of regulating greenhouse gases. On December 7, 2009, the EPA finalized its response to the Massachusetts, et al. v. EPA decision by issuing its “endangerment finding” that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. Moreover, on September 22, 2009, the EPA finalized 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 finalized 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. Finally, the May 2010 promulgation of regulations to control the greenhouse gas emissions from light-duty motor vehicles (the “tailpipe rule”) automatically triggered CAA provisions that, in general, require stationary source facilities that emit more than 25,000 tons per year of greenhouse gas 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 finalized the “tailoring rule,” which served to increase the greenhouse gas emissions threshold that triggers the permitting requirements for stationary sources. Under a phased-in approach, for most purposes, new permitting provisions are required for facilities that emit 100,000 tons per year or more of carbon dioxide equivalent. On June 26, 2012, the Circuit Court of Appeals for the District of Columbia circuit upheld the endangerment finding, as well as the tailpipe rule, and ruled that no petitioners had standing to challenge the timing and tailoring rules. Although it is not possible at this time to predict whether proposed legislation or regulations will be enforced as initially written, if at all, or how legislation or new regulation that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions.

The United States Congress has been considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs as discussed above. Any additional costs or operating restrictions associated with 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.

 

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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 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.

 

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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.

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 security 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 security 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.

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

 

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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;

 

   

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.

 

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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.

These exceptions also expressly permitted the reversal by Enbridge in 1999 of one of its pipelines that extends from Sarnia to Montreal, Quebec. As a result of this reversal, Enbridge competes with us to supply crude oil to the Ontario market.

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

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

 

   

The amount available for distributions on each unit may decrease;

 

   

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

 

   

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

Additionally, the public sale by our General Partner of a significant portion of the Class A or Class B common units 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

 

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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.

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.

 

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RISKS ARISING FROM OUR PARTNERSHIP STRUCTURE

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

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates through the policy renewal date of May 1, 2013. 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 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.

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

 

   

Incurring additional debt;

 

   

Entering into mergers or consolidations or sales of assets; and

 

   

Granting liens.

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

TAX RISKS TO COMMON UNITHOLDERS

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

 

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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 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.

 

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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 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 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.

 

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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.

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.

 

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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.

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.

 

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PART II

Item 5.    Market for Registrant’s Common Equity and Related Unitholder Matters

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 2012 and 2011 are summarized as follows:

 

     First      Second      Third      Fourth  

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  

2011 Quarters

           

High

   $ 33.86      $ 34.58      $ 30.24      $ 33.22  

Low

   $ 30.25      $ 28.50      $ 25.03      $ 24.66  

Cash distributions paid

   $ 0.51375      $ 0.51375      $ 0.53250      $ 0.53250  

On February 13, 2013, the last reported sales price of our Class A common units on the NYSE was $29.47. At January 31, 2013, there were approximately 90,000 Class A common unitholders, of which there were approximately 1,200 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.

Other Matters.    In January 2011, we issued 50,650 Class A common units in connection with a land acquisition, and in May 2012 we issued 64,464 Class A units in connection with another land acquisition. Both unit issuances were exempted from registration pursuant to Section 4(c) of the Securities Act of 1933, as amended.

 

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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 beginning at page 118. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

    December 31,  
    2012     2011     2010     2009     2008  
    (in millions, except per unit amounts)  

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

         

Operating revenues

  $ 6,706.1     $ 9,109.8     $ 7,736.1     $ 5,731.8     $ 9,898.7  

Operating expenses

    5,812.9       8,113.0       7,608.8       5,115.2       9,318.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    893.2       996.8       127.3       616.6       580.6  

Interest expense

    345.0       320.6       274.8       228.6       180.6  

Other income

    10.0       6.5       17.5       13.4       1.9  

Income tax expense

    8.1       5.5       7.9       8.5       7.0  

Noncontrolling interest

    57.0       53.2       60.6       11.4        
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

  $ 493.1     $ 624.0     $ (198.5   $ 381.5     $ 394.9  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

  $ 1.27     $ 1.99     $ (1.09   $ 1.12     $ 1.78  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash distributions paid per limited partner unit

  $ 2.1520     $ 2.0925     $ 2.0240     $ 1.9800     $ 1.9400  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

         

Property, plant and equipment, net

  $ 10,937.6     $ 9,439.4     $ 8,641.6     $ 7,716.7     $ 6,722.9  

Total assets

    12,796.8       11,370.1       10,441.0       8,988.3       8,300.9  

Long-term debt, excluding current maturities

    5,501.7       4,816.1       4,778.9       3,791.2       3,223.4  

Notes payable to General Partner

    330.0       342.0       347.4       269.7       130.0  

Partners’ capital:

         

Class A common units

    3,590.2       3,386.7       2,641.0       2,884.9       2,104.0  

Class B common units

    83.9       82.2       64.9       78.6       85.0  

Class C units(12)

                            886.5  

i-units

    801.8       728.6       579.1       588.8       553.8  

General Partner

    299.0       285.6       256.8       251.1       84.7  

Accumulated other comprehensive income (loss)

    (320.5     (316.5     (121.7     (74.6     12.9  

Noncontrolling interest

    793.5       445.5       465.4       341.1        
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Partners’ capital

  $     5,247.9     $     4,612.1     $     3,885.5     $     4,069.9     $     3,726.9  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

         

Cash flows provided by operating activities

  $ 851.0     $ 1,045.6     $ 377.9     $ 728.4     $ 543.3  

Cash flows used in investing activities

    1,906.6       1,099.0       1,427.8       1,173.6       1,428.3  

Cash flows provided by financing activities

    860.6       331.4       1,051.2       248.9       1,174.4  

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

    1,826.2        1,143.2       1,429.5       1,292.1       1,387.1  

 

(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: 2012, $129.3 million; 2011, $104.5 million; 2010, $61.6 million; 2009, $57.1 million; and 2008, $49.5 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  

December 2008

   9.875% Senior Notes      $ 500  

April 2008

   6.500% Senior Notes      $ 400  

April 2008

   7.500% Senior Notes      $ 400  

 

 

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.

 

 

For the year ended December 31, 2008 we made the following debt repayments:

   – $31.0 million of our First Mortgage Notes; and
   – $25.0 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  

December 2008

       Class A          32,500,000        $ 509.8  

March 2008

       Class A          9,200,000        $     221.8  

 

 

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

 

 

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

 

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(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

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  

2008

     $ 54.2        $ 72.2        $ 2.6        $ 286.7  

 

 

The quarterly in-kind distributions of 2.6 million, 2.4 million, 2.5 million, 3.3 million and 2.4 million i-units during 2012, 2011, 2010, 2009 and 2008, respectively, in lieu of cash distributions; and

 

 

The quarterly in-kind distributions of 1.6 million Class C units during both 2009 and 2008, 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, 2012, 2011 and 2010, 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, 2012, 2011 and 2010 we will incur aggregate gross costs of $55.0 million, $218.0 million and $595.0 million, respectfully, 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, 2012, and 2011 we recognized $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, 2012, Enbridge and its affiliates, including us, have exceeded the limits of coverage under this insurance policy, but expect to recover the remaining $145.0 million balance of our aggregate insurance coverage.

 

(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, will cost approximately $2.6 billion and will be undertaken on a cost-of-service basis and will be funded 60% by our General Partner and 40% by the Partnership under the Eastern Access Joint Funding Agreement. In conjunction with our application of the provisions of regulatory accounting, we recorded AEDC of $4.7 million for the year ended December 31, 2012, 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.

The following table reflects our operating income by business segment and corporate charges for each of the years ended December 31, 2012, 2011 and 2010.

 

     December 31,  
     2012     2011     2010  
     (in millions)  

Operating Income (loss)

      

Liquids

   $     706.8     $     816.2     $ (24.7

Natural Gas

     200.1       183.6           152.4  

Marketing

     (11.4     (0.8     3.7  

Corporate, operating and administrative

     (2.3     (2.2     (4.1
  

 

 

   

 

 

   

 

 

 

Total Operating Income

     893.2       996.8       127.3  

Interest expense

     345.0       320.6       274.8  

Other income

     10.0       6.5       17.5  

Income tax expense

     8.1       5.5       7.9  
  

 

 

   

 

 

   

 

 

 

Net income (loss)

     550.1       677.2       (137.9

Less: Net income attributable to noncontrolling interest

     57.0       53.2       60.6  
  

 

 

   

 

 

   

 

 

 

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

   $ 493.1     $ 624.0     $ (198.5
  

 

 

   

 

 

   

 

 

 

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.

 

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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, 2012 decreased $109.4 million, as compared with the same period in 2011, primarily due to the following:

 

   

Increased average daily volumes resulting in $25.1 million additional operating revenue;

 

   

Increased operating revenue of $17.0 million due to higher indexed tariff rates for our Lakehead, North Dakota and Ozark systems;

 

   

Increased operating revenue of $14.9 million for fees collected from our Cushing storage terminal facility;

 

   

Increased operating revenue of $11.8 million due to higher recovery of capital costs in our annual tolls related to the Line 6B Pipeline Integrity Plan;

 

   

Increased environmental costs, net of insurance recoveries, of $21.6 million for the year ended December 31, 2012 when compared to the same period of 2011;

 

   

Decreased unrealized, non-cash, mark-to-market net gains of $13.1 million for the year ended December 31, 2012, on derivative financial instruments that do not qualify for hedge accounting treatment;

 

   

Increased “Operating and administrative” expenses of $79.4 million primarily due to:

 

   

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

 

   

Increased supporting 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

 

   

Increased pipeline integrity costs of $11.2 million.

 

   

Increased Oil measurement adjustments due to a $52.2 million settlement with a shipper on our Lakehead crude oil pipeline system in 2011 that did not occur in 2012;

 

   

Increased power costs of $4.0 million primarily associated with the higher volumes of crude oil transported on our Lakehead system; and

 

   

Increased depreciation expense of $12.9 million for the year ended December 31, 2012, directly attributable to additional assets placed into service since 2011.

Natural Gas

Our Natural Gas segment consists of natural gas gathering and transmission pipelines as well as natural gas treating and processing plants and related facilities. The revenues of our Natural Gas segment are associated with services we provide to gather and process natural gas and to transport natural gas on our pipelines. Generally, our revenues are in the form of fee for service arrangements and sales of natural gas and NGLs.

 

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The operating income of our Natural Gas business for the year ended December 31, 2012 increased $16.5 million, as compared with the same period in 2011, primarily due to the following:

 

   

Decreased gross margin due to the significant decline in natural gas and NGL prices for the year ended December 31, 2012 when compared to the same period in 2011;

 

   

Increased operating revenue less the cost of natural gas derived from keep-whole processing earnings of $49.2 million;

 

   

Increased operating income of approximately $33.0 million due to “accounting misstatements” and “accounting errors” for NGL product purchases and sales made by our trucking and NGL marketing subsidiary for the year ended December 31, 2010 that were recorded for the year ended December 31, 2011 with no such misstatements or errors recorded for the year ended December 31, 2012;

 

   

Increased operating income of approximately $13.0 million due to unusually adverse weather conditions and plant downtime for the year ended December 31, 2011 that negatively impacted gross margin relative to typical weather related upsets experienced in 2012;

 

   

Increased fee-based operating income of approximately $13.0 million on our East Texas, Anadarko, and Oklahoma systems due to higher fees resulting from lower field operating pressures, contract changes, and additional Haynesville volumes;

 

   

Increased operating income of approximately $11.2 million from improved Anadarko NGL processing efficiencies and higher NGL content in the natural gas processing stream;

 

   

Increased operating income of approximately $10.8 million from our condensate marketing business due to higher realized margins from facilities placed into service during 2012;

 

   

Decreased operating income of $11.5 million in unrealized, non-cash, mark-to-market net gains from derivative instruments that do not qualify for hedge accounting treatment, as compared with the same period of 2011;

 

   

Increased operating and administration costs of $67.2 million for the year ended December 31, 2012, as compared with the same period in 2011 primarily due to:

 

   

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 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 2011;

 

   

Increased current year costs of $7.5 million for investigation costs related to accounting misstatements at our trucking and NGL marketing subsidiary;

 

   

Increased 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;

 

   

Increased current year costs of $4.3 million for the write down of surplus materials associated with the deferred portions of the Haynesville expansion within our East Texas system; and

 

   

Decreased depreciation expense of $7.8 million, for the year ended December 31, 2012, primarily due to a revision in depreciation rates for the Anadarko, North Texas and East Texas systems in 2011.

 

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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 income of our Marketing business for the year ended December 31, 2012 decreased $10.6 million, as compared with the same period of 2011. Primarily contributing to the operating loss of our Marketing business were lower and relatively stable natural gas prices during the year ended December 31, 2012, when compared to the same period of 2011, which limited opportunities to benefit from price differentials between market centers.

Additionally, the operating results of our Marketing business for the year ended December 31, 2012 included unrealized, non-cash, mark-to-market, net losses of $3.1 million associated with derivative financial instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with $0.7 million of unrealized, non-cash, mark-to-market, net gains for the year ended December 31, 2011.

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 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”

 

   

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

 

     December 31,  
     2012     2011     2010  
     (in millions)  

Liquids segment

      

Non-qualified hedges

   $       1.3     $     14.4     $ (2.8

Natural Gas segment

      

Hedge ineffectiveness

     3.1       (5.3           3.5  

Non-qualified hedges

     1.2       21.1       0.9  

Marketing

      

Non-qualified hedges

     (3.1     0.7       (6.7
  

 

 

   

 

 

   

 

 

 

Commodity derivative fair value net gains (losses)

     2.5       30.9       (5.1

Corporate

      

Hedge ineffectiveness

     (20.5     (0.3     —    

Non-qualified interest rate hedges

     (0.5     (0.5     (1.0
  

 

 

   

 

 

   

 

 

 

Derivative fair value net gains (losses)

   $ (18.5   $ 30.1     $ (6.1
  

 

 

   

 

 

   

 

 

 

 

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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,  
     2012     2011     2010  
     (in millions)  

Operating Results

      

Operating revenues

   $ 1,345.8     $ 1,285.4     $ 1,171.8  
  

 

 

   

 

 

   

 

 

 

Environmental costs, net of recoveries

     (91.3     (112.9     600.8  

Oil measurement adjustments

     (11.5     (63.4     5.6  

Operating and administrative

     383.0       303.6       259.9  

Power

     148.8       144.8       141.1  

Depreciation and amortization

     210.0       197.1       178.8  

Impairment charge

     —         —         10.3  
  

 

 

   

 

 

   

 

 

 

Operating expenses

     639.0       469.2       1,196.5  
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ 706.8     $ 816.2     $ (24.7
  

 

 

   

 

 

   

 

 

 

Operating Statistics

      

Lakehead system:

      

United States(1)

     1,405       1,327       1,302  

Province of Ontario(1)

     385       373       353  
  

 

 

   

 

 

   

 

 

 

Total Lakehead system delivery volumes(1)

     1,790       1,700       1,655  
  

 

 

   

 

 

   

 

 

 

Barrel miles (billions)

     480       450       439  
  

 

 

   

 

 

   

 

 

 

Average haul (miles)

     732       725       727  
  

 

 

   

 

 

   

 

 

 

Mid-Continent system delivery volumes(1)(2)

     223       226       212  
  

 

 

   

 

 

   

 

 

 

North Dakota system:

      

Trunkline

     203       193       159  

Gathering

     3       4       6  
  

 

 

   

 

 

   

 

 

 

Total North Dakota system delivery volumes(1)

     206       197       165  
  

 

 

   

 

 

   

 

 

 

Total Liquids segment delivery volumes(1)

     2,219       2,123       2,032  
  

 

 

   

 

 

   

 

 

 

 

(1) 

Average barrels per day in thousands.

 

(2) 

Includes average system deliveries of 7,000 Bpd for the year ended 2010, from the West Tulsa crude oil pipeline which was removed from service in September 2010.

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

 

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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.

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

 

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increase of $215.0 million for the year ended December 31, 2011. Additional environmental costs and insurance recoveries are discussed below under Operating Impact of Lines 6A and 6B Crude Oil Releases. 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, 2012, 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.

The increase in depreciation expense of $12.9 million for the year ended December 31, 2012 is directly attributable to the additional assets we have placed in service since the same period in 2011.

Operating Impact of Lines 6A and 6B Crude Oil Releases

We continue to perform necessary remediation, restoration and monitoring of the areas affected by the crude oil release from Line 6B of our Lakehead system. With respect to the Line 6B incident, we expect to make payments for additional costs associated with submerged oil and recovery operations, including remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. Primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, we have revised our total cost estimate to $820 million for the Line 6B incident, before insurance recoveries, for the year ended December 31, 2012, reflecting an increase of $55 million from our estimate at December 31, 2011. Our total cost estimate for the Line 6A crude oil release remains unchanged at approximately $48 million, before insurance recoveries and excluding additional fines and penalties. We continue to monitor this estimate to determine if our estimate should be updated. We have the potential of incurring additional costs in connection with these incidents including modified remediation requirements, other fines and penalties, as well as expenditures for litigation and settlement of claims. Our estimated costs for these incidents are based on currently available information and will be updated as considered necessary to incorporate material new information as it becomes available.

On July 2, 2012, we received a Notice of Probable Violation, or NOPV, from the PHMSA, related to the Line 6B crude oil release, which indicated a $3.7 million civil penalty that we paid during the third quarter of 2012. We have included the amount of the penalty in our total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012, the NTSB discussed the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012. We provided a reply to the NTSB on October 22, 2012 stating that we have either already or will soon be, fully implementing all of the NTSB recommendations.

On October 3, 2012, we received a letter from the EPA regarding a proposed order, which we refer to as the Proposed Order, for potential incremental containment and active recovery of submerged oil. We are in discussions with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. The nature and scope of any additional remediation activities that regulators may require is currently uncertain. Studies and additional technical evaluation by the EPA, the Partnership and other regulatory agencies may need to be completed before a final determination of any

 

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additional remediation activities can be determined. We have accrued the estimated costs we deem likely to be incurred. However, when a final determination of the appropriate nature and scope of any additional remediation is made, it could result in significant cost being accrued.

The claims for the crude oil release for Lines 6B were covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. We have exceeded the limits of coverage under this insurance policy. We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.

Enbridge’s current comprehensive insurance program, which became effective May 1, 2012 has a current liability aggregate limit of $660.0 million, including pollution liability, and will remain effective through April 30, 2013.

Year ended December 31, 2011 compared with year ended December 31, 2010

The operating revenue of our Liquids business increased for the year ended December 31, 2011 when compared with the same period in 2010 partially due to higher average daily delivery volumes on all three of our systems, when compared to the same period in 2010. The overall increase in average delivery volumes on our systems increased operating revenues by approximately $40.7 million for our Liquids segment. The total average daily deliveries from our liquid systems increased over four %, to 2.123 million barrels per day, or Bpd, for the year ended December 31, 2011 from 2.032 million Bpd for the same period in 2010. The increase in average deliveries on our liquid systems was partly attributable to the operation of Lines 6A and 6B, which were shut down for part of 2010 due to the Line 6A and Line 6B crude oil releases.

Average daily delivery volumes on our North Dakota system increased 19% during the year ended December 31, 2011 to 197,000 Bpd from 165,000 Bpd during the same period in 2010. The additional volumes were the result of an increase in capacity on our North Dakota system resulting from the elimination of segregated sour service on the system.

Further contributing to the increase in operating revenue was the completion of our Alberta Clipper Pipeline in April 2010. The Alberta Clipper Pipeline contributed approximately $34.8 million of additional operating revenue for the year ended December 31, 2011, when compared with the same period in 2010.

Another contributing factor to the increase in operating revenue is a $17.2 million increase in unrealized, non-cash, mark-to-market net gains related to derivative financial instruments as compared with the same period in 2010. In March 2010, we began to 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 executed 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.

Our transportation tariffs allow our pipelines to deduct an allowance from our customers for the transportation of their crude oil. We recognize revenue for this allowance at the prevailing market price for crude oil. The average prices of crude oil during the year ended December 31, 2011 were higher than the average prices for the same period of 2010. For example, the average allowance oil prices for North Dakota increased approximately 30% for the year ended December 31, 2011, as compared with the same period in 2010. Coupled with the increased liquids volumes, we have experienced an approximate $15.5 million increase in allowance oil revenues.

The operating results of our Liquids business were significantly affected by the crude oil releases from Lines 6A and 6B of our Lakehead system. At December 31, 2011, we revised our total estimate for this crude oil release to $765.0 million, an increase of $215.0 million from December 31, 2010. At December 31, 2011, we had

 

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made payments totaling $570.2 million for costs associated with the Line 6B crude oil release, $276.6 million of which relates to the year ended December 31, 2011. The decrease of $713.7 million in environmental expenses, net of recoveries for the year period ended December 31, 2011 when compared to the same period in 2010, is primarily due to recognizing $595.0 million of costs for the Line 6A and Line 6B incidents for the year of 2010 compared to $218.0 million of cost for these incidents offset by insurance recoveries of $335.0 million for the year ended December 31, 2011.

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 June 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.

The “Operating and administrative” expenses of our Liquids business increased $43.7 million from the year ended December 31, 2011, when compared with the same period in 2010 primarily due to the following:

 

   

Higher costs related to our pipeline integrity program;

 

   

Additional workforce related costs associated with the operational, administrative, regulatory and compliance support necessary for our systems;

 

   

Property tax increases associated with assets we constructed and placed in service;

 

   

Higher costs for repair and maintenance activities; and

 

   

Increases in other variable costs incurred in relation to our expanded pipeline systems.

Power costs increased $3.7 million for the year ended December 31, 2011, compared with the same period in 2010. The increase in power costs is primarily associated with the higher volumes of crude oil transported on all three of our liquids systems coupled with utility rate increases for power used by our Lakehead system.

The increase in depreciation expense of $18.3 million is directly attributable to the additional assets we have placed in service since the same period in 2010.

In September 2010, our West Tulsa crude oil pipeline was abandoned due to a significant decrease in throughput on the pipeline and, as a result, we recognized a $10.3 million impairment charge during the third quarter of 2010 to reduce the carrying amount of the asset to zero, as compared to no such impairments in the same period in 2011.

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. Historically, western Canada has been a key source of oil supply serving the United States’ energy needs. Canada’s oil sands, one of the largest oil reserves in the world, are an increasingly prominent source of supply. Over the last several years, as conventional crude oil production has declined, development of the Alberta Oil Sands has more than offset this reduction. The NEB estimates that total WCSB production averaged approximately 3.1 million Bpd in 2012 and 2.8 million Bpd in 2011. Volumes of WCSB crude oil production are comparable with production volumes from Iraq and Venezuela, key members of OPEC. The CAPP in June 2012 estimated future production from the Alberta Oil Sands to continue to grow steadily during the next 18 years, with an additional 3.4 million Bpd of incremental supply available by 2030, based on a subset of currently approved applications and announced expansions. We and Enbridge are actively working with our customers to develop transportation options that will allow Canadian crude oil greater access to markets in the United States.

 

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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 average approximately 2 million Bpd in 2013, which is 200,000 Bpd higher than the 1.8 million Bpd of actual deliveries in 2012. The ability to increase deliveries and to expand the Lakehead system in the future will ultimately depend upon a number of factors including crude oil prices, related development activities by crude oil producers in the region and competing pipelines.

North Dakota and Montana in the United States and the province of Saskatchewan in Canada have experienced tremendous growth in the development of crude oil and natural gas reserves from the Bakken formation. The latest data released in August 2012 by the EIA shows that proved reserves of crude oil in North Dakota have increased to 1.8 billion barrels at December 31, 2010, a 73% increase from December 31, 2009. Further, the Three Forks formations, located underneath the Bakken, is thought to be the next natural step in the development of this region.

In recent years rail transportation has emerged as an alternative method of shipping crude to market. While historically rail has not been considered an economically viable transportation solution for producers looking for market access, price spreads driven by limited transportation infrastructure to key markets and the lead time required to get new pipelines into service has opened up opportunities for the railway industry. These transportation and market access constraints have resulted in large crude oil price differences between the North Dakota supply basin and refining market centers. As a result, crude oil producers have begun moving increasing amounts of oil by rail which has increased competition to our North Dakota system and decreased our system utilization. We expect this competition to decrease our 2013 volumes, compared to our volumes for the year ended December 31, 2012. Future pipeline expansions and enhanced market access to eastern Canadian markets and eastern PADD II are expected to decrease current crude oil price differentials. Crude oil producers are expected to then shift their volumes back to pipelines as the primary transportation option since pipeline transportation costs are significantly less costly than rail. We continue to solidify our long term position in the Bakken formation, and the announcement of several expansion projects should increase our available capacity within this region.

The table below summarizes the Partnership’s commercially secured projects for the Liquids segment, which will be placed into service in future periods.

 

Projects

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

Eastern Access Projects

        

Line 5, Line 62 Expansion, Line 6B Replacement

   $     2,050        2013—2014         Joint (1) 

Eastern Access Upsize—Line 6B Expansion

     364        Early 2016         Joint (1) 

U.S. Mainline Expansions

        

Line 67 & Line 61 (phase 1)

     420        Q3 2014         Joint (2) 

Chicago Area Connectivity (Line 62 twin)

     495        Mid 2015         Joint (2) 

Line 61 (phase 2)

     1,250        Mid 2015, 2016         Joint (2) 

Line 67 (phase 3)

     240        2015        Joint (2) 

Berthold Rail

     145        Q1 2013         EEP   

Bakken Pipeline Expansion

     300        Q1 2013         EEP   

Bakken Access Program

     100        Mid 2013         EEP   

Sandpiper Project

     2,500        Early 2016         EEP   

Line 6B 75-mile Replacement Program

     317        Q4 2013         EEP   

 

(1) 

Jointly funded 40% by the Partnership and 60% by our General Partner under Eastern Access Joint Funding agreement. Estimated capital costs presented are before our General Partner’s contributions.

 

(2) 

Jointly funded 40% by the Partnership and 60% by our General Partner under Mainline Expansion Joint Funding agreement. Estimated capital costs presented are before our General Partner’s contributions.

 

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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 expansion will involve construction of an approximately 600-mile 24-inch diameter line from Beaver Lodge, North Dakota, to the Superior, Wisconsin, mainline system terminal. The new line will twin the 210,000 Bpd North Dakota system mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 225,000 Bpd of capacity on the twin line between Beaver Lodge and Clearbrook and 375,000 Bpd between Clearbrook and Superior. The Sandpiper Project is estimated to cost approximately $2.5 billion and will be fully funded by the Partnership. The capital cost will be rolled into the existing North Dakota System rate base, with the associated cost-of-service to be recovered in tolls. The pipeline is expected to begin service in early 2016, subject to regulatory approvals.

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 in Canada in the provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States. One of the projects involves the expansion of the Partnership’s Line 5 light crude line between Superior, Wisconsin and Sarnia, Ontario by 50,000 Bpd. Complementing the Line 5 expansion, Enbridge announced plans to reverse portions of its Line 9A and Line 9B in western Ontario to permit crude oil movements eastbound from Sarnia to Westover, Ontario and as far as Montreal, Quebec. The Line 5 expansion is targeted to be in service during the first quarter of 2013, and the Line 9A and Line 9B reversal is targeted to be in service in late 2013 and in 2014, respectively. 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 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.

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, between Flanagan, Illinois and the Terminal at Griffith, Indiana by adding horsepower to increase capacity from 130,000 Bpd to 235,000 Bpd, and an additional 330,000 barrel crude oil tank at Griffith; and 2) replacement of additional sections of the Partnership’s Line 6B in Indiana and Michigan to increase capacity from 240,000 Bpd to 500,000 Bpd. Portions of the existing 30-inch diameter pipeline will be replaced with 36-inch diameter pipe. Subject to customary regulatory approvals, these projects are expected to be placed in-service during 2013 and 2014. These projects, including the previously announced Line 5 expansion, 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 is until July 2021.

As part of The Light Oil Market Access Program announced in December 2012, the Partnership will upsize the Eastern Access projects, which includes further expansion of the Line 6B component with increasing capacity

 

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from 500,000 Bpd to 570,000 Bpd, at an expected cost of approximately $364 million. This further expansion of the Line 6B component is expected to begin service in early-2016.

These projects collectively referred to as the Eastern Access Projects, will cost approximately $2.5 billion and will be undertaken on a cost-of-service basis and will be funded 60% by our General Partner and 40% by the Partnership under a Eastern Access Joint Funding Agreement. Before June 30, 2013, the Partnership has the option to reduce its funding and associated economic interest in the projects by up to 15 percentage points down to 25%. Additionally, within one year of the last project in-service date, scheduled for early 2016, the Partnership will also have the option to increase its economic interest held at that time by up to 15 percentage points.

U.S. Mainline Expansion

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 finalization of scope and regulatory and shipper 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 third quarter of 2014.

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 $1,250 million. Some of the overall expansion is expected to begin service in mid-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 line pipe construction. Subject to regulatory approvals, the pipeline is expected 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. The projects will be jointly funded by our General Partner at 60% and the Partnership at 40%, under a Mainline Expansion Joint Funding Agreement which parallels the Eastern Access Joint Funding Agreement. Before June 30, 2013, the Partnership has the option to reduce its funding and associated economic interest in the projects by up to 15 percentage points down to 25%. Additionally, within one year of the last project in-service date, scheduled for early 2016, the Partnership will also have the option to increase its economic interest held at that time by up to 15 percentage points.

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

Enbridge, the ultimate parent of our General Partner, also announced in May 2012 complementary Eastern Access and Mainline Expansion Projects which included: (1) 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

 

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and Ohio; (2) subject to regulatory approval, a reversal of Enbridge’s Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec, (3) expansions to add horsepower on existing lines on the Enbridge Mainline system from western Canada to the U.S. border.

Berthold Rail

In December 2011, we announced that we will be proceeding with the Berthold Rail Project, a $145 million investment that will provide an interim solution to shipper needs in the Bakken region. The project will expand pipeline capacity into the Berthold, North Dakota Terminal by 80,000 Bpd and includes 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 an additional capacity of 10,000 Bpd to the Berthold Terminal. The loading facility and the crude oil tankage are expected to be placed into service during the first quarter of 2013.

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 the states of Montana and North Dakota and the Canadian provinces of Saskatchewan and Manitoba. The Bakken Project will follow 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 will expand 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 calls for an expansion at our existing terminal and station in Berthold, North Dakota. Upon completion in the first quarter of 2013, the Bakken Project will provide capacity of 145,000 Bpd. This project, with the North Dakota mainline, will result in a total takeaway capacity for this region of 355,000 Bpd. The United States portion of the Bakken Project will have an estimated cost of approximately $300 million. We commenced construction in July of 2011 with an expected in-service date in the first quarter of 2013. In February 2012, we and Enbridge Income Fund Holdings in Canada, announced a second open season for the Bakken Project to allow shippers the option of securing future capacity once the expansion is completed. The open season resulted in additional term commitments to support the Bakken Project.

Bakken Access Program

In October 2011, we announced the Bakken Access Program, a series of projects totaling approximately $100 million, which represents an upstream expansion that will further complement our Bakken Project, as discussed above. This expansion program will substantially enhance our gathering capabilities on the North Dakota system by 100,000 Bpd. This program is expected to be in service by mid-2013, and it involves increasing pipeline capacities, constructing additional storage tanks and adding truck access facilities at multiple locations in western North Dakota.

Cushing Terminal Storage Expansion Project

In July 2012, engineering design commenced on three new tanks and associated infrastructure totaling 936,000 barrels of incremental shell capacity at our Cushing terminal. The three additional tanks will have an estimated cost of $39 million and are targeted to be in service by the fourth quarter-2013.

In January 2012, we began construction on four new tanks at our Cushing South Terminal with an approximate shell capacity of 1.2 million barrels. As of December 31, 2012, estimated costs on the project were $33 million, and all four tanks were completed and placed into service.

 

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During late 2010, we began construction on nine new storage tanks at our Cushing terminal with an approximate shell capacity of 3.2 million barrels. As of December 31, 2012, we spent approximately $60 million and all nine tanks were completed and placed in service.

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 at an estimated cost of $286.0 million. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments of pipeline are targeted to be placed in service during 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through our Facilities Surcharge Mechanism, or FSM, which is part of the system-wide rates of the Lakehead system. We have subsequently revised the scope of this project to increase the diameter of all pipe segments upstream of Stockbridge, Michigan at a cost of approximately $31.0 million, which will bring the total capital for this replacement program to an estimated cost of $317.0 million. The $31.0 million of additional costs will be recovered through the FSM.

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.

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 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

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 from Freeport, Texas to Cushing, Oklahoma, as well as a Texas City Terminal and Distribution System which serves refineries in Houston and Texas City areas. Seaway also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast. In the second quarter of 2012, the direction of the 500-mile Seaway pipeline was reversed to enable transportation of 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, has increased the capacity to approximately 400,000 Bpd, depending upon the mix of light and heavy grades of crude oil.

In March 2012, based on additional capacity commitments from shippers, plans were announced to proceed with an expansion of the Seaway Pipeline through construction of a second line that is expected to more than double its capacity to 850,000 Bpd by mid-2014. In addition, 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 560,000 Bpd, and subject to regulatory approval, is expected to be available in mid-2014.

 

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Southern Access Extension

In December 2012, Enbridge announced that they will 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 a binding open season to solicit commitments from shippers for capacity on the proposed pipeline. The open season closed in January 2013 and Enbridge is evaluating the results. Prior to launching the open season, Enbridge already received sufficient capacity commitments from an anchor shipper to support the 24-inch pipeline as proposed. Subject to regulatory approval, the project is expected to be placed into service in 2015.

Other Matters

Line 6B Pipeline Integrity Plan

We completed on schedule all the work required by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, that we agreed to perform as part of our restart of Line 6B in September 2010. Additionally, a new line was installed beneath the St. Clair River in March 2011 and tied into the existing pipeline during June 2011, and we announced plans for the pipeline replacement plan discussed under Line 6B 75-mile Replacement Program above. Additional integrity expenditures, which could be significant, may be required after this initial remediation program. The total cost of these integrity measures is separate from the remediation, restoration and monitoring costs discussed above. The pipeline integrity and replacement costs will be capitalized or expensed in accordance with our capitalization policies as these costs are incurred, the majority of which are expected to be capital in nature. We expect to incur ongoing operating costs for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems.

We included in the supplement to our FSM, which was effective April 1, 2011, recovery of $175 million of capital costs and $5 million of operating costs for the 2010 and 2011 Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, which include an equity return component, interest expense and an allowance for income taxes will be recovered over a 30 year period, while operating costs will be recovered through our annual tolls for actual costs incurred. These costs include costs associated with the PHMSA Corrective Action Order and other required integrity work.

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. The pressure restrictions will remain in place until such time we can demonstrate that the root cause of the incident has been remediated.

 

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Natural Gas

Our Natural Gas segment consists of natural gas gathering and transmission pipelines, as well as treating and processing plants and related facilities. Collectively, these systems include:

 

   

Approximately 11,400 miles of natural gas gathering and transmission pipelines;

 

   

Eight active treating plants and 25 active processing plants, including two hydrocarbon dewpoint control facilities, or HCDP plants. We may idle some of these plants from time to time based on current volumes; and

 

   

Trucks, trailers and railcars used for transporting NGLs, crude oil and other products.

The following tables set forth the operating results of our Natural Gas segment assets and approximate average daily volumes of our major systems in millions of British Thermal Units per day, or MMBtu/d, for the periods presented.

 

     December 31,  
     2012      2011     2010  
     (in millions)  

Operating revenues

   $ 3,967.7      $ 5,692.5     $ 4,230.1  
  

 

 

    

 

 

   

 

 

 

Cost of natural gas

     3,172.7        4,973.8       3,641.9  

Environmental costs, net of recoveries

             (0.4      

Operating and administrative

     460.1        392.9       303.6  

Depreciation and amortization

     134.8        142.6       132.2  
  

 

 

    

 

 

   

 

 

 

Operating expenses

     3,767.6        5,508.9       4,077.7  
  

 

 

    

 

 

   

 

 

 

Operating Income

   $ 200.1      $ 183.6     $ 152.4  
  

 

 

    

 

 

   

 

 

 

Operating Statistics (MMBtu/d)

       

East Texas

     1,266,000        1,378,000       1,259,000  

Anadarko

     1,017,000        1,013,000       711,000  

North Texas

     330,000        337,000       356,000  
  

 

 

    

 

 

   

 

 

 

Total(1)

     2,613,000        2,728,000       2,326,000  
  

 

 

    

 

 

   

 

 

 

 

(1) 

Average daily volumes for the years ended December 31, 2012, 2011 and 2010 include 255,000 MMBtu/d, 251,000 MMBtu/d, and 66,000 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 derive revenue in our Natural Gas segment from the following types of arrangements:

Fee-Based and Take-or-Pay Arrangements

Under a fee-based contract, we receive a set fee for gathering, treating, processing and transporting raw natural gas and providing other similar services. These revenues correspond with the volumes and types of services we provide and do not depend directly on commodity prices. Revenues of our Natural Gas segment that are derived from transmission services consist of reservation fees charged for transmission 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 transmission volumes. Reservation fees are required to be paid whether or not the shipper delivers the volume, thus referred to as a take-or-pay arrangement. Additional revenues from our intrastate pipelines are derived from the combined sales of natural gas and transmission services.

 

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Other Arrangements

We also use other types of arrangements to derive revenues for our Natural Gas segment. These arrangements expose us to commodity price risk, which we substantially mitigate with offsetting physical purchases and sales of natural gas, NGLs and condensate, and by 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 other types of arrangements we use to derive revenues for our Natural Gas business 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 then sell at market prices and retain as our fee.

 

   

Percentage-of-Liquids Contracts—Under these contracts, we receive a negotiated percentage of NGLs extracted from natural gas that requires processing, which we then sell at market prices and retain as our fee. This contract structure is similar to percentage-of-proceeds arrangements except that we only receive a percentage of the NGLs and we generally contractually provide the customer their share of NGLs regardless of actual NGL production. This type of contract may also require the processor to provide a guaranteed NGL recovery percentage to the customer.

 

   

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

 

   

Keep-Whole Contracts—Under these contracts, we gather or purchase raw natural gas from the producer for processing. A portion of the gathered or purchased natural gas is consumed during processing. We extract and retain the NGLs produced during processing for our own account, which we sell at market prices. In instances where we purchase raw natural gas at the wellhead, we also sell for our own account at market prices, the resulting residue gas. In those instances when we gather and process raw natural gas for the account of the producer, we must return to the producer residue natural gas with an energy content equivalent to the original raw natural gas we received as measured in British thermal units, or Btu.

Under the terms of each of these contract structures, we retain a portion of the natural gas and NGLs as our fee in exchange for providing these producers with our services. As of December 31, 2012, we are exposed to fluctuations in commodity prices in the near term on approximately 20% to 30% of the natural gas, NGLs and condensate we expect to receive as compensation for our services. Due to this unhedged commodity price exposure, our 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 processed natural gas, NGLs and condensate, even though the market price of these commodities will continue to fluctuate during that time. Many of the derivative financial instruments we use do not qualify for 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 unrealized non-cash gains and losses in our reported operating results that can be significant during periods when the commodity price environment is volatile.

 

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

Revenue for our Natural Gas business is derived from the fees or commodities we receive from the gathering, transportation, processing and treating of natural gas and NGLs for our customers. For the year ended December 31, 2012, prices for natural gas and NGLs declined significantly when compared to prices for the same period in 2011. Average natural gas prices declined approximately 31% per MMBtu based upon the New York Mercantile Exchange, or NYMEX, Henry Hub pricing index, for the year ended December 31, 2012, when compared to the same period in 2011. NGLs declined approximately 30% and 28% per composite barrel, for the year ended December 31, 2012 as compared to the same period in 2011, based upon the Conway and Mont Belvieu pricing hubs, respectively.

Changing industry fundamentals have resulted in significant downward pressure in current and forward NGL prices, specifically in ethane and propane. We expect the near term outlook for our Natural Gas segment will be negatively impacted by this recent decline in NGL prices, resulting in a reduction to our 2013 gross margin and the overall earnings of the Natural Gas segment.

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, 2012 increased $49.2 million from the same period in 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.

Operating income for the year ended December 31, 2012, when compared to the same period in 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 the prior year, our volumes were negatively impacted due to uncharacteristically cold weather and freezing precipitation in February 2011 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 business for the year ended December 31, 2011.

For the year ended December 31, 2012, operating income increased $13.0 million, when compared to the same period during 2011, due to fee-based contracts on our East Texas, Anadarko, and Oklahoma systems. The increase in fee-based operating income is 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.

 

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Operating income also increased $11.2 million, for the year ended December 31, 2012 when compared to the same period in 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, operating income from our condensate marketing business for the year ended December 31, 2012 increased approximately $10.8 million, from the same period in 2011, due to higher realized margins from enhancements of facilities that were placed into service during 2012.

Operating income of our Natural Gas business experienced unrealized, 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 that caused their related earnings to become reclassified as realized, non-cash, mark-to-market gains rather than unrealized. 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 same period of 2011. 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.

The following table depicts the effect that unrealized, non-cash, mark-to-market net gains and losses had on the operating results of our Natural Gas segment for the years ended December 31, 2012 and 2011:

 

     For the years ended December 31,  
              2012                         2011            
     (in millions)  

Hedge ineffectiveness

   $               3.1      $ (5.3

Non-qualified hedges

     1.2                      21.1  
  

 

 

    

 

 

 

Derivative fair value gains

   $ 4.3      $ 15.8  
  

 

 

    

 

 

 

Operating and administrative costs of our Natural Gas segment were $67.2 million higher for the year ended December 31, 2012 compared to the same period in 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 to write down project line pipe to net realizable value, as well as, expense development, engineering and other costs associated with a project in East Texas. Due to lower levels of producer activity in the East Texas region, this project was deferred to a later date and it was determined that these costs and line pipe have uncertain future benefit. As such, these costs were expensed and the line pipe written down for the year ended December 31, 2012. There were no similar adjustments for the same period in 2011.

Depreciation expense for our Natural Gas segment decreased $7.8 million, for the year ended December 31, 2012 compared with the same period of 2011, primarily due to a revision in depreciation rates for the Anadarko,

 

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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 same period of 2011. This decrease was offset with an increase in depreciation expense associated with additional assets that were put in service during late 2011.

Year ended December 31, 2011 compared with year ended December 31, 2010

Revenue for our Natural Gas business is derived from the fees or commodities we receive from the gathering, transportation, processing and treating of natural gas and NGLs for our customers. We were exposed to fluctuations in commodity prices in the near term on approximately 30% to 40% of the natural gas, NGLs and condensate we expected to receive as compensation for our services. As a result of this unhedged commodity price exposure, our 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. NGL prices were higher for the year ended December 31, 2011 compared to prices in the same period in 2010, which positively impacted our operating income by $58.9 million due to the move favorable pricing environment.

Our volumes and revenues are the result of wellhead supply contracts and drilling activity in the areas served by our Natural Gas business, primarily the Bossier Trend, Barnett Shale, Granite Wash and the Haynesville Shale. During the year ended December 31, 2011, natural gas volumes on our systems increased approximately 17%, in relation to the same period of 2010, primarily due to production increases in the Granite Wash and new assets placed in service to capture the growing production from the Haynesville shale play. Volumes on our Anadarko system increased 42% for the year ended December 31, 2011 compared with the same period in 2010, of which the majority of the increase was associated with the Elk City system we acquired in September 2010 representing an additional 185,000 MMBtu/d.

Although volumes were higher on the majority of our systems for the year ended December 31, 2011 compared with the same period of 2010, in February 2011 uncharacteristically cold weather and freezing precipitation moved through Oklahoma and north Texas with temperatures dropping below freezing for extended periods. These conditions resulted in mechanical issues with our producers’ equipment and impacted their ability to flow natural gas. Producers shut in significant volumes during this period, which reduced the average daily volumes on our systems by approximately 56,000 MMBtu/d, in the first quarter of 2011, or approximately 14,000 MMBtu/d for the year ended December 31, 2011. 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 business for year ended December 31, 2011.

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, 2011 was $41.5 million, representing a decrease of $24.4 million from the $65.9 million we produced for the same period in 2010.

The reduction in keep-whole earnings was a result of the increasing production of liquids rich natural gas on our Anadarko system, excluding the Elk City acquisition, where a significant number of our contracts are POL type arrangements. This earnings decrease is largely attributable to paying natural gas producers for liquids we were unable to recover due to gas volume increasing faster than our available capacity. The rapid increase in supply exceeded our processing capacity as evidenced by the 18% increase in average daily volumes from 645,000 MMBtu/d to 762,000 MMBtu/d on the system for the year ended December 31, 2011 compared to the same period last year.

 

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Changes in the average forward prices of natural gas, NGLs and condensate from December 31, 2010 to December 31, 2011 produced unrealized, non-cash, mark-to-market net gains of $15.8 million from the non-qualifying commodity derivatives we use to economically hedge a portion of the natural gas, NGLs and condensate resulting from the operating activities of our Natural Gas business. The net gains resulted primarily from the fractionation hedge gains on the settlement of our 2011 hedge losses as well as gains on the market movement on new fractionation hedges, offset by losses on the settlement of 2011 gas hedges.

Comparatively, changes in the average forward prices of natural gas, NGLs and condensate from December 31, 2009 to December 31, 2010, produced unrealized, non-cash, mark-to-market net gains of $4.4 million from the non-qualifying commodity derivatives we use to economically hedge a portion of the natural gas, NGLs and condensate resulting from the operating activities of our Natural Gas business. The average forward and daily prices for natural gas at December 31, 2010 were lower relative to natural gas prices at December 31, 2009, while the average forward and daily prices of NGLs were higher though the end of 2012 and lower thereafter relative to NGL prices at December 31, 2009. As a result of the lower natural gas forward prices, we experienced unrealized mark-to-market net gains on derivatives we use to fix the price of natural gas we sell. Partially offsetting the gains were unrealized mark-to-market net losses on the derivatives that we use to hedge our fractionation margins, which represent the relative difference between the price we receive from the sale of NGLs and the corresponding cost of natural gas we purchase for processing. As a result of lower natural gas forward prices and the higher NGL forward prices, fractionation margins widened producing these derivative losses.

The following table depicts the effect that unrealized, non-cash, mark-to-market net gains and losses had on the operating results of our Natural Gas segment for the years ended December 31, 2011 and 2010:

 

     For the years ended December 31,  
             2011                     2010          
     (in millions)  

Hedge ineffectiveness

   $ (5.3   $ 3.5  

Non-qualified hedges

                   21.1                     0.9  
  

 

 

   

 

 

 

Derivative fair value gains

   $ 15.8     $ 4.4  
  

 

 

   

 

 

 

Operating and administrative costs of our Natural Gas segment were $89.3 million higher for the year ended December 31, 2011 compared to the same period in 2010, primarily due to the expansion of our systems, including the Elk City system we acquired in September 2010 and a common carrier trucking company we acquired in October 2010. Increased maintenance costs and workforce related costs for the year ended December 31, 2011 when compared to the same period in 2010 also contributed to the increased operating and administrative costs.

Depreciation expense for our Natural Gas segment increased $10.4 million for the year ended December 31, 2011 compared to the same period in 2010, primarily due to an increase in depreciation associated with the Elk City system we acquired in September 2010 and additional assets that were put in service during 2010. This increase was partially offset by a revision in depreciation rates for the Anadarko, North Texas and East Texas systems effective July 1, 2011, which extended the depreciable lives of the systems and lowered depreciation expense approximately $17.0 million.

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

 

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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 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 will be placed into service in future periods.

 

Project

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

Texas Express Pipeline

   $ 385        Mid 2013         Joint (1) 

Ajax Cryogenic Processing Plant

   $ 230        Mid 2013         EEP   

 

(1) 

Our ownership of the Texas Express Pipeline is 35%. Estimated capital cost presented is only our portion of the costs.

Texas Express Pipeline

In September 2011, we announced a joint venture among us, Enterprise Products, and Anadarko Petroleum Corporation, or Anadarko, to design and construct a new NGL pipeline and two new NGL gathering systems, collectively referred to as the Texas Express Pipeline project, or TEP. In April 2012, DCP Midstream LLC, or DCP, announced plans to purchase a 10% ownership in the NGL pipeline portion of TEP from Enterprise Products. After DCP’s purchase, the NGL pipeline portion of TEP is owned 35% by Enterprise Products, 35% by us, 20% by Anadarko and 10% by DCP, while the ownership in the two new NGL gathering systems will be owned 45% by Enterprise Products, 35% by us and 20% by Anadarko. Our portion of the total estimated cost is

 

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$385 million. The pipeline will originate at Skellytown, Texas and extend approximately 580-miles to NGL fractionation and storage facilities in Mont Belvieu, Texas. The pipeline will have an initial capacity of approximately 280,000 Bpd and will be readily expandable to approximately 400,000 Bpd. Approximately 250,000 Bpd of capacity has been subscribed on the pipeline.

In addition, the TEP joint venture project will include two new NGL gathering systems. The first will connect TEP NGL pipeline to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and Western Oklahoma. The second NGL gathering system will connect the new pipeline to central Texas, Barnett Shale processing plants. Volumes from the Rockies, Permian Basin and Mid-Continent regions will be delivered to the TEP 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 will be able to access TEP through the connecting Front Range Pipeline as proposed by Enterprise Products, DCP and Anadarko. Enterprise Products will construct and serve as the operator of the pipeline, while we will build and operate the new gathering systems. The pipeline and portions of the gathering systems are expected to begin service in mid-2013, subject to regulatory approvals and finalization of commercial agreements.

TEP will serve as a link between growing supply sources of NGLs in the Anadarko region and the primary end use market on the United States Gulf Coast and will provide guaranteed NGL access to the primary United States petrochemical market located in Mont Belvieu. TEP will assist us in fulfilling our strategic objective of expanding our presence in the natural gas and NGL value chain and provide us with a new source of strong and stable cash flow.

Ajax Cryogenic Processing Plant

In August 2011, we announced plans to construct an additional processing plant and other facilities, including compression and gathering infrastructure, on our Anadarko system at a cost of $230 million, which we refer to as our Ajax Plant. The Ajax Plant has a planned capacity of 150 million cubic feet per day, or MMcf/d, and is intended to meet the continued strength of horizontal drilling activity in this area. The Ajax Plant is anticipated to be in service in mid-2013.

The Ajax plant, when operational, in addition to the Allison Plant, will increase the total processing capacity on our Anadarko system to approximately 1,200 MMcf/d.

South Haynesville Shale Expansion

In February 2010, we announced plans to expand our East Texas system by constructing three lateral pipelines into the East Texas portion of the Haynesville Shale, together with a large diameter lateral pipeline from Shelby County to Carthage which will further expand our recently completed Shelby County Loop. The expansion into the Haynesville Shale area increased the capacity of our East Texas system by 900 MMcf/d. We completed construction of a portion of the pipeline for the project during the second quarter of 2010 and the main trunkline to Carthage in December 2010. Construction of the facilities was completed in the second quarter of 2012.

In April 2011, we announced plans to invest an additional $175 million to expand our East Texas system. We have signed long-term agreements with four major natural gas producers along the Texas side of the Haynesville Shale to provide gathering, treating and transmission services in Shelby, San Augustine and Nacogdoches counties. The projects involve construction of gathering and related market outlet pipelines and related treating facilities in the Texas Haynesville Shale. Due to lower levels of producer activity, in light of weak natural gas prices, the Partnership has deferred portions of its Haynesville natural gas expansion pending increases in drilling activity.

 

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Other Matters

Elk City System Acquisition

On September 16, 2010, we acquired 100% ownership of the entities that comprise the Elk City system for $686.1 million in cash, including amounts for working capital. The Elk City system extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle. The Elk City system consists of approximately 800 miles of natural gas gathering and transportation pipelines, one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 million cubic feet per day, or MMcf/d, and a combined current natural gas liquid production capability of 20,000 barrels per day. The acquisition of the Elk City system complements our existing Anadarko natural gas system by providing additional processing capacity and expansion capability. The results of operations of the Elk City system have been included in our consolidated financial statements within our Natural Gas segment from the September 16, 2010 acquisition date.

Marketing

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

 

     December 31,  
     2012     2011     2010  
     (in millions)  

Operating revenues

   $     1,392.6     $     2,131.9     $     2,334.2  
  

 

 

   

 

 

   

 

 

 

Cost of natural gas

     1,397.4       2,126.3       2,321.4  

Operating and administrative

     6.6       6.3       8.9  

Depreciation and amortization

           0.1       0.2  
  

 

 

   

 

 

   

 

 

 

Operating expenses

     1,404.0       2,132.7       2,330.5  
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

   $ (11.4   $ (0.8   $ 3.7  
  

 

 

   

 

 

   

 

 

 

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

 

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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 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, 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 same period in 2011 primarily due to the continued erosion of natural gas prices and associated differentials.

Natural gas prices during 2012 were lower and relatively stable as compared to the same period of 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 same period in 2011.

Included in the operating results of our Marketing segment for the year ended December 31, 2012 were unrealized, non-cash, mark-to-market net losses of $3.1 million as compared with $0.7 million of unrealized non-cash, mark-to-market net gains for the same period in 2011 associated with derivative instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance. This increase in unrealized, non-cash, mark-to-market net losses for the year ended December 31, 2012, as compared to the same period in 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.

 

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Year ended December 31, 2011 compared with year ended December 31, 2010

The operating results of our Marketing segment for the year ended December 31, 2011 decreased by $4.5 million when compared to the same period in 2010.

Included in the operating results of our Marketing segment for the year ended December 31, 2011 were unrealized, non-cash, mark-to-market net gains of $0.7 million associated with derivative financial instruments that did not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with the $6.7 million of unrealized non-cash, mark-to-market net losses for the same period in 2010. For the year ended December 31, 2011, the non-cash, mark-to-market net gains primarily resulted from financial instruments that we used to hedge our storage positions. The net gains associated with our storage derivative instruments resulted from the narrowing 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. Comparatively, for the year ended December 31, 2010, the non-cash, mark-to-market net loss primarily resulted from the realizations of financial transactions entered into in prior years and realized in 2010.

Offsetting the unrealized, non-cash, mark-to-market net gains and contributing to the operating loss of our Marketing segment were relatively stable natural gas prices during 2011, which limited opportunities to benefit from significant price differentials between market centers.

Operating income for the year ended December 31, 2011 was also negatively affected by non-cash charges of $2.8 million we recorded to reduce the cost basis of our natural gas inventory to net realizable value compared to $1.0 million of similar charges in the comparable period of 2010.

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,  
     2012     2011     2010  
     (in millions)  

Operating and administrative expenses

   $ 2.3     $ 2.2     $ 4.1  
  

 

 

   

 

 

   

 

 

 

Operating loss

     (2.3     (2.2     (4.1

Interest expense

         345.0           320.6           274.8  

Other income

     10.0       6.5       17.5  

Income tax expense

     8.1       5.5       7.9  
  

 

 

   

 

 

   

 

 

 

Net loss

     (345.4     (321.8     (269.3

Net loss attributable to Noncontrolling interest

     57.0       53.2       60.6  
  

 

 

   

 

 

   

 

 

 

Net loss attributable to general and limited partners

   $ (402.4   $ (375.0   $ (329.9
  

 

 

   

 

 

   

 

 

 

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

 

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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.

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 cost incurred

   $ 381.3      $ 334.2  
  

 

 

    

 

 

 

Interest cost 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.

Year ended December 31, 2011 compared with year ended December 31, 2010

The increase in our net loss in 2011 was mostly attributable to the increase in interest expense as compared to the same period in 2010. This increase in interest expense is primarily the result of a higher weighted average outstanding debt balance during the year ended December 31, 2011 as compared with the same period in 2010. The increased weighted average outstanding debt balance was primarily a result of the following:

 

   

An increase in our weighted average balance of commercial paper outstanding for the year ended December 31, 2011 of $706.3 million compared to $328.3 million during the same period in 2010; and

 

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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.

For the year ended December 31, 2011, we recorded $0.8 million of unrealized, non-cash, mark-to-market net losses associated with the changes in fair value of these derivatives that resulted from the decrease in interest rates from December 31, 2010 to December 31, 2011. For the year ended December 31, 2010, we recorded $1.0 million of unrealized, non-cash, mark-to-market net losses associated with the changes in fair value of these derivatives that resulted from the decrease in interest rates from December 31, 2009 to December 31, 2010.

Our interest cost for the years ended December 31, 2011 and 2010 is detailed below:

 

     December 31,  
     2011      2010  
     (in millions)  

Interest expense

   $     320.6      $     274.8  

Interest capitalized

     13.6        8.7  
  

 

 

    

 

 

 

Interest cost incurred

   $ 334.2      $ 283.5  
  

 

 

    

 

 

 

Interest cost paid

   $ 314.3      $ 257.6  
  

 

 

    

 

 

 

Weighted average interest rate

     6.4%         6.4%   

Our income tax expense is $5.5 million and $7.9 million for the years ended December 31, 2011 and 2010, respectively, 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.

Other Matters

Alberta Clipper Pipeline Joint Funding Arrangement and Regulatory Accounting

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 $53.9 million, $53.2 million and $60.6 million to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline for the years ended December 31, 2012, 2011 and 2010, 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.

In connection with our application of the regulatory accounting provisions to our Alberta Clipper Pipeline, we recorded AEDC in “Other income (expense)” on our consolidated statement of income. For the year ended December 31, 2010, we recorded $15.3 million and $4.8 million, of AEDC and AIDC, or allowance for interest during construction, respectively, on our consolidated statements of income related to the Alberta Clipper Pipeline. There were no additional costs recorded in 2012 or 2011 as all assets were placed into service as of December 31, 2010.

Proceeds from Claim Settlements

We received proceeds of $11.6 million, in 2011, for settlement of claims we made for payment from unrelated parties in connection with operational matters that occurred in the normal course of business. We recorded $5.6 million as a reduction to “Operating and administrative” expenses of our Liquids segment and $6.0 million as “Other income” in our consolidated statements of income for the year ended December 31, 2011 for the amounts we received in April 2011. There were no similar transactions in 2012.

 

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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 $2.0 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 $675.0 million credit agreement with JPMorgan Chase Bank as administrative agent, and a syndicate of 12 lenders, which we refer to as the 364-Day Credit Facility. We refer to the 364-Day Credit Facility and the Credit Facility as our Credit Facilities. We access our commercial paper program primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our Credit Facilities.

As set forth in the following table, we had approximately $1.5 billion of liquidity available to us at December 31, 2012 to meet our ongoing operational, investment and financing needs, as well as the funding requirements associated with the environmental costs resulting from the crude oil releases on Lines 6A and 6B.

 

     (in millions)  

Cash and cash equivalents

   $ 227.9  

Total credit available under Credit Facilities

     2,675.0  

Less: Amounts outstanding under Credit Facilities

      

Principal amount of commercial paper issuances

     1,160.0  

Letters of credit outstanding

     231.8  
  

 

 

 

Total

   $     1,511.1  
  

 

 

 

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. 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, 2012, we had a working capital deficit of approximately $546.1 million and over $1.5 billion of liquidity to meet our ongoing operational, investing and finance needs as of December 31, 2012 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.

 

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Capital Resources

Equity and Debt Securities

Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private equity and credit markets to obtain the capital necessary to fund these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our internal growth projects and targeted acquisitions will require additional permanent capital and require us to bear the cost of constructing and acquiring assets before we begin to realize a return on them. If market conditions change and capital markets again become constrained, our ability and willingness to complete future debt and equity offerings may be limited. 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.

Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit issuances for cash for the years ended December 31, 2012, 2011 and 2010 other than pursuant to the Equity Distribution Agreement, or EDA, and the Amended and Restated Equity Distribution Agreement, or Amended EDA described below.

 

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    
  

 

 

       

 

 

    

 

 

    

 

 

 

2010

              

November(5)(6)

     11,960,000      $30.06        $347.4        $7.4        $354.8    
  

 

 

       

 

 

    

 

 

    

 

 

 

 

(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.

 

(5) 

The proceeds from the November 2010 equity issuance were used to repay short term indebtedness incurred to finance the Elk City system acquisition and capital expansion projects.

 

(6) 

Amounts adjusted for the April 21, 2011 stock split.

Equity Distribution Agreement

In June 2010, we entered into the 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

 

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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 EDA and remained unsold as of that date.

On May 27, 2011, the Partnership entered into the 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.

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 years ended December 31, 2012 and 2011:

 

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  
  

 

 

       

 

 

    

 

 

    

 

 

 

2010

              

April 1 to June 30(3)

     574,690      $ 26.26      $ 14.8      $ 0.3      $ 15.1  

July 1 to September 30(3)

     1,373,482      $ 27.11        36.3        0.7        37.0  

October 1 to December 31(3)

     289,230      $ 27.85        7.6        0.2        7.8  
  

 

 

       

 

 

    

 

 

    

 

 

 

2010 Totals(3)

     2,237,402         $ 58.7      $ 1.2      $ 59.9  
  

 

 

       

 

 

    

 

 

    

 

 

 

 

(1) 

Net of commissions and issuance costs of $2.2 million and $1.2 million for the years ended December 31, 2011 and 2010, respectively.

 

(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.

Investments

In November 2011, Enbridge Management completed a private offering of 860,684 listed shares, representing limited liability company interests in Enbridge Management with limited voting rights, at a price of $29.86 per listed share. Enbridge Management received net proceeds of $25.5 million which were subsequently invested in an equal number of our i-units. We used the proceeds to finance a portion of our capital expansion program relating to the expansion of our core liquids and natural gas systems and for general corporate purposes.

Available Credit

Our two primary sources of liquidity are provided by our commercial paper program and our Credit Facilities. We have a $1.5 billion commercial paper program that is supported by our Credit Facilities, which we access primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities.

 

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Credit Facilities

In September 2011, we entered into the Credit Facility. The agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $2.0 billion, a letter of credit subfacility and a swing line subfacility. Effective September 26, 2012, we extended the maturity date to September 26, 2017 and amended it to adjust the base interest rates.

On July 6, 2012, we entered into the 364-Day Credit Facility. The agreement is a committed senior unsecured revolving credit facility pursuant to which the lenders have committed to lend us up to $675.0 million: 1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion; and 2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods.

On February 8, 2013, we amended the $675 million unsecured senior revolving credit agreement to reflect an increase in the lending commitments to $1.1 billion. We use the unsecured revolving credit agreement to fund our general activities and working capital needs. The amended $1.1 billion credit agreement has terms consistent with our 364-Day Credit Facility. After this amendment, our Credit Facilities provide an aggregate amount of $3.1 billion of bank credit.

The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. It is our policy to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at such time. Taking that policy into account, at December 31, 2012, we could borrow $1,283.2 million under the terms of our Credit Facilities, determined as follows:

 

     (in millions)  

Total credit available under Credit Facilities

   $   2,675.0  

Less: Amounts outstanding under Credit Facilities

      

Principal amount of commercial paper outstanding

     1,160.0  

Letters of credit outstanding

     231.8  
  

 

 

 

Total amount we could borrow at December 31, 2012

   $ 1,283.2  
  

 

 

 

Individual London Interbank Offered Rate, or LIBOR rate, borrowings under the terms of our Credit Facilities may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the Credit Facilities and do not require any cash repayments or prepayments. For the year ended December 31, 2010, we renewed LIBOR rate borrowings of $1,284.0 million, on a non-cash basis.

Effective September 30, 2011, our Credit Facility was amended to further modify the definition of Consolidated Earnings Before Income Taxes Depreciation and Amortization, or Consolidated EBITDA, as set forth in the terms of our Credit Facility, to increase from $550 million to $650 million, the aggregate amount of the costs associated with the crude oil releases on Lines 6A and 6B that are excluded from the computation of Consolidated EBITDA. Specifically, the costs allowed to be excluded from Consolidated EBITDA are those for emergency response, environmental remediation, cleanup activities, costs to repair the pipelines, inspection costs, potential claims by third parties and lost revenue. As of December 31, 2012, we were in compliance with the terms of our financial covenants.

Commercial Paper

At December 31, 2012, we had $1.2 billion of commercial paper outstanding at a weighted average interest rate of 0.46%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net borrowings of approximately $884.9 million during the year ended December 31, 2012, which

 

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include gross borrowings of $9,141.6 million and gross repayments of $8,256.7 million. Our policy is that the commercial paper we can issue is limited by the amounts available under our Credit Facility up to an aggregate principal amount of $1.5 billion. Our commercial paper program was increased from $1.0 billion in August 2011.

Senior Notes

All of our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $300.0 million of senior notes issued by the Enbridge Energy, Limited Partnership, or OLP, which we refer to as the OLP Notes. The borrowings under our senior notes are non-recourse to our General Partner and Enbridge Management. All of our senior notes either pay or accrue interest semi-annually and have varying maturities and terms.

The OLP, our operating subsidiary that owns the Lakehead system, has $300.0 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes. All of the OLP Notes pay interest semi-annually and have varying maturities and terms.

In September 2011, we issued and sold $600.0 million in aggregate principal amount of senior notes due 2021, which we refer to as the 2021 Notes. The 2021 Notes bear interest at the rate of 4.20% per year and will mature on September 15, 2021. Interest on the 2021 Notes is payable on March 15 and September 15 of each year, beginning on March 15, 2012. Also in September 2011, we issued and sold an additional $150.0 million in aggregate principal amount of our 5.50% notes due in 2040, which we refer to as the 2040 Notes. The additional 2040 Notes will be fully fungible with, rank equally in right of payment with and form a part of the same series as the existing 2040 Notes, originally issued by us in September 2010, for all purposes under the governing indenture. We received net proceeds from the note offerings in September 2011 of approximately $740.7 million after payment of underwriting discounts and commissions and our estimated offering expenses. We used the net proceeds from these offerings to repay a portion of our outstanding commercial paper, to fund a portion of our capital expansion projects and for general corporate purposes.

Junior Subordinated Notes

The Junior Subordinated Notes, which we refer to as the Junior Notes, consist of our 8.05% fixed/floating rate, unsecured, long-term junior subordinated notes due 2067, with a principal amount outstanding of $400.0 million. The Junior Notes are subordinate in right of payment to all of our existing and future senior indebtedness, as defined in the related indenture.

Joint Funding Arrangements

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

Joint Funding Arrangement for Alberta Clipper Pipeline

In July 2009, we entered into a joint funding arrangement to finance the construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge. The Alberta Clipper Pipeline was mechanically complete in March 2010 and was ready for service on April 1, 2010.

In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement by issuing a promissory note payable to our General Partner, which we refer to as the A1 Term Note. At such time we also terminated the A1 Credit Agreement. The A1 Term Note

 

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matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400 million. The terms of the A1 Term Note are similar to the terms of our 5.20% senior notes due 2020, except that the A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline. Under the terms of the A1 Term Note, we have the ability to increase the principal amount outstanding to finance the debt portion of the investment our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement to finance any additional costs associated with the construction of our portion of the Alberta Clipper Pipeline we incur after the date the original A1 Term Note was issued. The increases we make to the principal balance of the A1 Term Note will also mature on March 15, 2020. At December 31, 2012, we had approximately $330.0 million outstanding under the A1 Term Note.

Our General Partner also made equity contributions totaling $3.3 million to the OLP during the year ended December 31, 2011, to fund its equity portion of the construction costs associated with the Alberta Clipper Pipeline. No such contributions were made for the year ended December 31, 2012. The OLP paid a distribution of $59.9 million and $76.4 million to our General Partner and its affiliate during the years ended December 31, 2012 and 2011 for their noncontrolling interest in the Series AC, representing limited partner ownership interests of the OLP that are specifically related to the assets, liabilities and operations of the Alberta Clipper Pipeline.

We allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $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, 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, the OLP amended and restated its limited partnership agreement 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. All assets, liabilities and operations related to the Eastern Access Projects are owned 60% by our General Partner and 40% by the Partnership as per the funding agreement we refer to as the Eastern Access Joint Funding Agreement. Before June 30, 2013, the Partnership has the option to reduce its funding and associated economic interest in the projects by up to 15 percentage points down to 25%. Additionally, within one year of the last project in-service date, scheduled for early 2016, the Partnership will also have the option to increase its economic interest held at that time by up to 15 percentage points.

Our General Partner has made equity contributions totaling $347.9 million to the OLP during the year ended December 31, 2012 to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Joint Funding Arrangement for Mainline Expansion Projects

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. The projects will be 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. We also have an option, exercisable prior to June 30, 2013, for the Partnership to reduce its funding and associated economic interest in the projects by up to 15 percentage points down to 25%. Additionally, within one year of the last project in-service date, scheduled for early 2016, the Partnership will also have the option to increase its economic interest held at that time by up to 15 percentage points.

 

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Our General Partner has made equity contributions totaling $3.0 million to the OLP during the year ended December 31, 2012 to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.

Restrictive Covenants

Our Credit Facility contains restrictive covenants that require us to maintain a maximum leverage ratio of 5.00 to 1.00. At December 31, 2012, we were in compliance with the covenants associated with our Credit Facility. Our Credit Facility also places limitations on the debt that our subsidiaries may incur directly. Accordingly, it is expected that we will provide debt financing to our subsidiaries as necessary.

Our senior notes are subject to make-whole redemption rights and were issued under an indenture containing certain covenants that restrict our ability, with certain exceptions, to sell, convey, transfer, lease or otherwise dispose of all or substantially all of our assets, except in accordance with our indenture agreement. We were in compliance with these covenants at December 31, 2012.

The OLP Notes do not contain any covenants restricting us from issuing additional indebtedness by the OLP. The OLP Notes are subject to make-whole redemption rights and were issued under an indenture, referred to as the OLP Indenture, containing certain covenants that restrict our ability, with certain exceptions, to sell, convey, transfer, lease or otherwise dispose of all or substantially all of our assets, except in accordance with the OLP Indenture. We were in compliance with these covenants at December 31, 2012.

Cash Requirements

Capital Spending

We expect to make additional expenditures during 2013 for the acquisition and construction of natural gas processing and crude oil transportation infrastructure. In 2013, we expect to spend approximately $3.4 billion on system enhancements and other projects associated with our liquids and natural gas systems with the expectation of realizing additional cash flows as projects are completed and placed into service. We expect to receive funding of approximately $ 1.1 billion from our General Partner based on our joint funding arrangement for the Eastern Access Projects and Mainline Expansion Projects. We made expenditures of $2.0 billion for the year ending December 31, 2012, inclusive of $168.5 million in contributions to the Texas Express Pipeline and $350.9 million of expenditures that were financed by contributions from our General Partner via the joint funding arrangement. At December 31, 2012, we had approximately $681.3 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment during 2013.

Acquisitions

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

Forecasted Expenditures

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

 

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connects, to our natural gas gathering systems as core maintenance expenditures. Enhancement expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards.

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. Given sustained natural gas prices and weaker NGL prices for ethane and propane, our Natural Gas business will face challenges over our near-term planning horizon. As such, with our focus to exercise prudent financial management and optimize our capital, we plan to reduce capital investment into the natural gas business in the near term. We will continue to consider opportunities in the natural gas business that will elevate our long-term, fee-based profile or strengthen our existing assets.

The following table sets forth our estimates of capital expenditures we expect to make for system enhancement and core maintenance for the year ending December 31, 2013. Although we anticipate making these expenditures in 2013, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets. We made capital expenditures of $2.0 billion, including $123.8 million on core maintenance activities, for the year ended December 31, 2012. For the full year ending December 31, 2013, we anticipate our capital expenditures to approximate the following:

 

     Total
Forecasted
Expenditures
 
     (in millions)  

Capital Projects

  

Eastern Access Projects

   $ 1,395  

U.S. Mainline Expansions

                510  

North Dakota Expansion Program

     205  

Line 6B 75-mile Replacement Program

     95  

Liquids Integrity Program

     285  

Ajax Cryogenic Processing Plant

     55  

System Enhancements

     565  

Core Maintenance Activities

     130  

Joint Venture Projects

  

Texas Express Pipeline

     185  
  

 

 

 
     3,425  

Less: Joint Funding by General Partner

     1,145  
  

 

 

 
   $ 2,280  
  

 

 

 

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

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