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TABLE OF CONTENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS, SUPPLEMENTARY INFORMATION AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES ENBRIDGE ENERGY PARTNERS, L.P.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended DECEMBER 31, 2007

OR

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

For the transition period from                    to                  

Commission File Number: 1-10934

ENBRIDGE ENERGY PARTNERS, L.P.
(Exact name of Registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)		   39-1715850
(I.R.S. Employer Identification No.)

1100 Louisiana
Suite 3300
Houston, Texas 77002
(Address of principal executive offices and zip code)

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

Securities registered pursuant to Section 12(g) of the Act: NONE

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

         Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No ý

         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 ý No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. ý

         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.

Large Accelerated Filer ý   Accelerated Filer o

Non-Accelerated Filer o
 
Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

         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, 2007, was $3,067,260,854.

         As of February 20, 2008 the Registrant has 55,238,834 Class A common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS

 
    
    
 
    
   Page
    PART I    
Item 1.   Business   1
Item 1A.   Risk Factors   35
Item 1B.   Unresolved Staff Comments   47
Item 2.   Properties   47
Item 3.   Legal Proceedings   47
Item 4.   Submission of Matters to a Vote of Security Holders   47

 
 
PART II
 
 
Item 5.   Market for Registrant's Common Equity and Related Unitholder Matters   48
Item 6.   Selected Financial Data   49
Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations   51
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk   94
Item 8.   Financial Statements and Supplementary Data   101
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   101
Item 9A.   Controls and Procedures   101
Item 9B.   Other Information   102

 
 
PART III
 
 
Item 10.   Directors, Executive Officers and Corporate Governance   103
Item 11.   Executive Compensation   108
Item 12.   Security Ownership of Certain Beneficial Owners and Management   122
Item 13.   Certain Relationships and Related Transactions, and Director Independence   123
Item 14.   Principal Accountant Fees and Services   126

 
 
PART IV
 
 
Item 15.   Exhibits and Financial Statement Schedules   127
Signatures   128
Index to Consolidated Financial Statements   F-1

        This Annual Report on Form 10-K contains forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "continue," "estimate," "expect," "forecast," "intend," "may," "plan," "position," "projection," "strategy," "could," "should," or "will" or the negative of those terms or other variations of them or comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate revenue, income or cash flow are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. 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 our ability to control or predict. For additional discussion of risks, uncertainties and assumptions, see "Item 1A. Risk Factors" included elsewhere in this Form 10-K.

i


Glossary

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

AEUB   Alberta Energy and Utilities Board
Anadarko system   Natural gas gathering and processing assets located in western Oklahoma and the Texas panhandle, which were acquired on October 17, 2002
AOCI   Accumulated other comprehensive income
AOSP   Athabasca Oil Sands Project, located in northern Alberta, Canada
Bbl   Barrel of liquids (approximately 42 U.S. gallons)
BlackRock   BlackRock Ventures Inc., an unrelated producer of heavy oil in Western Canada
Bpd   Barrels per day
CAA   Clean Air Act
Canadian Natural   Canadian Natural Resources Limited, an unrelated energy company
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   Department of Transportation
East Texas system   Natural gas gathering, treating and processing assets in East Texas acquired on November 30, 2001. Also includes a system formerly known as the Northeast Texas system acquired October 17, 2002.
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 System
Enbridge Pipelines   Enbridge Pipelines Inc.
EnCana   EnCana Corporation, an unrelated producer of natural gas and crude oil
EP Act   Energy Policy Act of 1992
EPACT   Energy Policy Act of 2005
EPA   Environmental Protection Agency
Exchange Act   Securities Exchange Act of 1934, as amended
FASB   Financial Accounting Standards Board
FERC   Federal Energy Regulatory Commission
General Partner   Enbridge Energy Company, Inc., general partner of the Partnership
HCA   High consequence area
ICA   Interstate Commerce Act
KPC   Kansas Pipeline system, sold on November 1, 2007
Lakehead Partnership   Enbridge Energy, Limited Partnership, a subsidiary of the Partnership
Lakehead system   U.S. portion of the System
LIBOR   London Interbank Offered Rate—British Bankers Association's average settlement rate for deposits in U.S. dollars
M3   Cubic meters of liquid = 6.2898105 Bbl
MLP   Master Limited Partnership
MMBtu/d   Million British Thermal units per day
MMcf/d   Million cubic feet per day
Midcoast system   Natural gas gathering, treating, processing, transmission and marketing assets acquired October 17, 2002

ii

Mid-Continent system   Crude oil pipelines and storage facilities located in the mid-continent of the U.S. and acquired on March 1, 2004
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
NOPR   Notice of Proposed Rulemaking issued by the FERC.
North Dakota system   Liquids petroleum pipeline system in the Upper Midwest United States acquired on May 18, 2001
Northeast Texas system   Natural gas gathering and processing assets acquired on October 17, 2002 and integrated with the East Texas system
North Texas system   Natural gas gathering and processing assets acquired on December 31, 2003
NYMEX   The New York Mercantile Exchange where natural gas futures, options contracts, and other energy futures are traded
NYSE   New York Stock Exchange
OCSLA   Outer Continental Shelf Lands Act
OSHA   Occupational Safety and Health Administration
OPA   Oil Pollution Act
OPS   Office of Pipeline Safety
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
PADD IV   Consists of Idaho, Montana, Wyoming and Colorado
PADD V   Consists of Washington, Oregon, California, Arizona, Alaska, Hawaii and Nevada
Palo Duro system   Natural gas transmission and gathering pipeline assets located in Texas between the Anadarko system and the North Texas system acquired on March 1, 2004 and integrated with the Anadarko system during 2005
Partnership Agreement   Fourth Amended and Restated Agreement of Limited Partnership of the Enbridge Energy Partners, L.P.
Partnership   Enbridge Energy Partners, L.P. and its consolidated subsidiaries
PHMSA   Pipeline and Hazardous Materials Safety Administration (formerly OPS)
PIPES of 2006   Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006
PIPES Act   Pipeline Safety Act Reauthorization of 2006
PPIFG   Producer Price Index for Finished Goods
PSA   Pipeline Safety Act
PSI Act   Pipeline Safety Improvement Act
RCRA   Resource Conservation & Recovery Act
SAGD   Steam assisted gravity drainage
SEC   Securities and Exchange Commission
SEP II   System Expansion Program II, an expansion program on the Lakehead system
Settlement Agreement   A FERC approved settlement agreement, signed October 1996

iii

SFAS   Statement of Financial Accounting Standards
SFPP   Santa Fe Pacific Pipelines, L.P., an unrelated pipeline company
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
System   The combined liquid petroleum pipeline operations of the Lakehead system and the Enbridge system
Tariff Agreement   A 1998 offer of settlement filed with the FERC
Terrace   Terrace Expansion Program, an expansion program on the Lakehead system
WCSB   Western Canadian Sedimentary Basin

iv


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 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 NYSE under the symbol "EEP."

        We were formed in 1991 by our general partner to own and operate the Lakehead system, which is the U.S. 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. A subsidiary of Enbridge owns the Canadian portion of the System. Enbridge, which is based in Calgary, Alberta, provides 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 relating to the midstream energy sector. As of December 31, 2007, our portfolio of assets include the following:

        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."

        Our ownership at December 31, 2007 is comprised of the following:

 
   2007
  
Class A common units owned by the public   59.6 %
Class B common units owned by our general partner   4.2 %
Class C units owned by our general partner   6.4 %
Class C units owned by institutional investors   13.1 %
i-units owned by Enbridge Management   14.7 %
General Partner interest   2.0 %
   
 
    100.0 %
   
 

1

BUSINESS STRATEGY

        Our primary objective is to provide stable and sustainable cash distributions to our unitholders, while maintaining a relatively low investment risk 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:

        In our current environment, our primary focus is on expanding and developing our existing assets. We continue to place relatively less emphasis on acquisitions than we have in past years due to:

        While purchase prices remain high, our acquisitions will likely be limited to situations where we have natural advantages, through reduced costs or increased utilization of our services.

        Our planned internal growth for both our liquids and natural gas businesses will require a significant investment of expansion capital over the next few years. While these major projects are under construction, we will bear the associated capital costs for these investments before we begin to realize a return on them. We expect our larger growth projects will be accretive to distributable cash flow when placed into service. These projects are discussed below in the respective business section.

2

Liquids

        The following map presents the locations of our current Liquids systems assets and projects being constructed:

GRAPHIC

        This map depicts some assets owned by Enbridge and projects being constructed to provide an understanding of how they interconnect with our Liquids systems.

        Western Canadian crude oil is an important source of supply for the United States. According to the latest available data for 2007 from the U.S. Department of Energy's Energy Information Administration, Canada supplied approximately 1.7 million barrels per day, or Bpd, of crude oil to the U.S., the largest source of U.S. imports. Approximately 67 percent of the Canadian crude oil moving into the U.S. was transported on the System, the primary pipeline from western Canada to the U.S. We are well positioned to develop additional infrastructure to deliver growing volumes of crude oil that are expected from the Alberta oil sands. With an estimated $110 billion in Canadian dollars, or CAD, of active or planned projects in the Alberta oil sands, new production is expected to grow steadily during the next five years, with an additional 2.3 million Bpd of incremental supply available by 2015, according to the Canadian Association of Petroleum Producers, or CAPP.

        Our Southern Access project is the cornerstone of our mainline expansion initiatives to address the expected increase in supply of Western Canadian crude oil. Our $2.1 billion project will provide an additional 400,000 Bpd of heavy crude oil capacity to the Chicago market and beyond by early 2009, with nearly half of this capacity available in early 2008. The design will also permit a further 800,000 Bpd increase in capacity for minimal additional cost, in conjunction with a corresponding expansion upstream

3


of Superior. The Southern Access project involves new pipeline construction on our Lakehead system along with expansion on the Canadian portion of the pipeline by Enbridge.

        Additionally, we and Enbridge are developing the Alberta Clipper pipeline project, which will involve construction of a 1,000 mile, 36-inch diameter, heavy crude oil pipeline from Hardisty, Alberta to Superior, Wisconsin with an initial capacity of 450,000 Bpd that is expandable to 800,000 Bpd. Our share of the cost of this project as currently proposed will be approximately $1.0 billion in 2007 dollars, excluding capitalized interest. Alberta Clipper is expected to be in-service by the middle of 2010. Regulatory applications were filed with the National Energy Board in May 2007 for the Canadian segment of the project, and the hearings were concluded in the fourth quarter of 2007. In the United States, regulatory and permit applications are in progress at state and federal levels, and engineering and public consultations are underway.

        Along with Enbridge, we are actively working with our customers to develop options that will allow Canadian crude oil to access new markets. The market strategy we are undertaking is to provide timely, economical, integrated transportation solutions to connect growing supplies of production from the Alberta oil sands to key refinery markets in the United States. The strategy involves further penetration into PADD II as well as entry into the vast refining center of the U.S. Gulf Coast. In December 2007, Enbridge and ExxonMobil Pipeline Company announced the two companies will conduct a Solicitation for Binding Shipper Commitment (Commitment Solicitation) for a proposed new pipeline system to transport crude oil from Patoka, Illinois, to the Texas Gulf Coast. The new pipeline to be called the "Texas Access Pipeline," would transport crude oil sourced from the Canadian oil sands region in Alberta, Canada, and from the upper Midwest to refiners in the Nederland and Houston, Texas areas. The proposed project includes a new 768-mile, 30-inch diameter pipeline, which would transport crude oil from Patoka, Illinois, southward to Nederland, Texas. Also proposed is an 88-mile, 24-inch pipeline to transport crude oil onward from Nederland to a delivery point in the east Houston area. The Commitment Solicitation is for shipper interest in executing binding commitments to transport specified volumes of crude oil on the new pipeline, which is expected to be completed in 2011. The results of the Commitment Solicitation will guide and determine the further development of the proposed joint venture pipeline.

        The strategy of further penetration into PADD II is also evidenced by the Enbridge expansion of the Spearhead pipeline system from 125,000 Bpd to 190,000 Bpd. Our Lakehead system carries Western Canadian crude oil as far as Chicago, where it is transferred to the Spearhead pipeline that runs from Chicago, Illinois to the refinery and storage hub located at Cushing, Oklahoma.

4

Natural Gas

        The following map presents the locations of assets for our Natural Gas systems:

GRAPHIC

        This map depicts some assets owned by Enbridge to provide an understanding of how they relate to our Natural Gas systems.

        Our natural gas assets are primarily located in the U.S. Gulf Coast region, one of the most active natural gas producing areas in the United States. Three of our larger systems in Texas are located in basins that are experiencing consistent drilling and production growth. These core basins are known as the East Texas basin, the Fort Worth Basin and the Anadarko basin. Our focus has been on expanding the service capability of our existing assets and acquiring assets with strong growth prospects located in or near these areas where we already operate or have a competitive advantage.

        One of our key goals is to become the premier midstream energy company in the U.S. Gulf Coast region. To achieve this end, 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, enhance our reputation 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. This latter objective we intend to achieve by increasing customer access to preferred natural gas markets. We have made significant progress on attaining this objective with construction of our East Texas Expansion project, otherwise known as Clarity, which includes an intrastate pipeline connecting our East Texas system at Bethel, Texas to multiple downstream interconnects and by physically connecting a number of our systems.

5


The aim is to be able to move significant quantities of natural gas from our Anadarko, North Texas and East Texas systems to the major market hubs in Texas and Louisiana, which Clarity provides. 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.

        Our Natural Gas business also includes trucking operations that we use to enhance the value of the NGLs produced at our processing plants by ensuring ready access to strategic markets. Our 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.

        The growth prospects in our core areas are primarily a result of strong commodity prices, rig utilization rates and improvements in technology to produce natural gas from tight sand and shale formations. As a result, many expansions and extensions have been made on three of our main gathering and processing systems in Texas, including well-connects, processing plant re-activations, new plant construction, added compression, new pipelines and treating plant re-activations.

        We continue to work closely with our customers to provide natural gas transportation solutions to avoid shut-in natural gas production from insufficient transportation capacity. In January 2006, we announced an expansion and extension of our East Texas system to handle the strong growth occurring in East Texas natural gas production, particularly from the Bossier Sands and other regional producing formations. We coordinated extensively with our customers to develop and enhance access for growing Texas natural gas production to major markets in southeast Texas. We have firm volume commitments and acreage dedications on our Clarity project, which we believe by the end of 2008 will approximate 600 MMcf/d. The intrastate pipeline has 700 MMcf/day of capacity that will be available when construction is completed in early 2008 and additional compression is added in mid-2008. The project is designed to be expandable and is positioned for potential upstream and downstream extension.

        In addition to the expansion of our transportation capacity to meet the needs of our customers, we have also expanded our processing and treating capacity on our three major systems to meet the growing demand for these services and to capture the additional revenue these services provide. In 2007 we added 195 MMcf/d of processing capacity with the commissioning of the Hidetown plant on our Anadarko system and the expansions of the Weatherford plant on our North Texas system. We added three hydrocarbon dewpoint control facilities with total capacity of 550 MMcf/d on our East Texas system at Carthage, Grapeland and Henderson, Texas to meet the increasingly more stringent natural gas pipeline transportation specifications. Lastly, we enhanced the ability of our 275 MMcf/d treating facility at Aker, Texas to handle additional sour gas being produced in the southeast Texas area and we commissioned our 200 MMcf/d treating facility at Marquez, Texas which feeds directly into the intrastate pipeline we are constructing in connection with our Clarity project.

BUSINESS SEGMENTS

        We conduct our business through three business segments:

        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 16 of our consolidated financial statements beginning on page F-1 of this report.

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Liquids Segment

Lakehead system

        The Lakehead system consists primarily of a crude oil and liquid petroleum common carrier pipeline and terminal assets in the Great Lakes and Midwest regions of the United States. This system, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. The System, which spans approximately 3,300 miles, has been in operation for over 50 years and is the primary transporter of crude oil and liquid petroleum from western Canada to the United States. The System serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the Province of Ontario, Canada. We and Enbridge have undertaken the Southern Access, Alberta Clipper and other expansion projects to increase the capacity of the Lakehead and Enbridge mainline systems in an effort to capitalize on the expected increases in crude oil supplies from previously announced heavy crude oil and oil sands projects in the Province of Alberta, Canada.

        Our Lakehead system is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission, or FERC. The Lakehead system spans a distance of approximately 1,900 miles, and consists of approximately 3,500 miles of pipe with diameters ranging from 12 inches to 48 inches, 60 pump station locations with a total of approximately 846,450 installed horsepower and 64 crude oil storage tanks with an aggregate capacity of approximately 11.6 million barrels. The System operates in a segregation, or batch mode, allowing the transport of 43 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 2007, approximately 30 shippers tendered crude oil and liquid petroleum for delivery through the 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. Similar to U.S. domestic conventional crude oil production, western Canada's conventional crude oil production is declining. Over the last several years, development of the Alberta oil sands resource has more than offset declining conventional production. The NEB estimated that total production in 2007 from the Western Canadian Sedimentary Basin, or WCSB, averaged approximately 2.4 million Bpd compared with 2.3 million bpd in 2006. WCSB crude oil production is comparable with production from key OPEC members Kuwait and Venezuela.

        Remaining established conventional oil reserves in western Canada were estimated to be approximately 3.7 billion barrels at the end of 2006. During 2006, the latest period for which data is available, approximately 66 percent of conventional production was replaced with reserve additions. Remaining established reserves from the Alberta oil sands as of the end of 2006 stand at approximately 173 billion barrels. Combined conventional and oil sands established reserves of approximately 179 billion barrels compares with Saudi Arabia's proved reserves of approximately 264 billion barrels.

        According to the CAPP, an estimated $60 billion CAD has been spent on oil sands development from 1996 through 2006. A survey of CAPP members and oil sands developers estimate that oil producers may spend an additional $110 billion CAD by 2011, including all announced and planned oil sands projects. Although it is unlikely that all projects will proceed as planned, the investment already in place and the number and size of companies involved provides strong evidence of ongoing oil sands industry expansion. CAPP estimates future production from the Alberta oil sands will increase by more than 2.3 million barrels per day by 2015 based on a subset of currently approved applications and announced expansions.

7

        The near-term growth in crude oil supply comes from the completion and consolidation of major expansion projects at existing synthetic crude oil upgraders and growth of bitumen production from both existing and new Steam Assisted Gravity Drainage, or SAGD facilities currently under construction. Over the next year, synthetic crude oil production is expected to increase by approximately 315,800 Bpd from the following sources:

        Syncrude completed a 100,000 Bpd Stage 3 expansion in 2006, increasing total production capacity to 350,000 Bpd. However, the new Stage 3 coker suffered from a number of start-up issues that prevented Syncrude from attaining full utilization of its production capacity, even through 2007. Production for the year averaged approximately 304,000 Bpd. Syncrude's next expansion will de-bottleneck the current system to increase synthetic production by approximately 40,000 Bpd to approximately 390,000 Bpd by 2012.

        Suncor completed its 35,000 Bpd expansion in late 2005 resulting in total upgrading capacity of 260,000 Bpd. Average synthetic production from the upgrader was 229,000 Bpd in 2007, lower than capacity as a result of the scheduled shutdown of one of two upgraders to allow the tie-in of new facilities related to a planned expansion. Suncor also received conditional approval from the AEUB for its proposed Voyageur expansion, which will increase synthetic production capacity to 550,000 Bpd by 2012. Over the next year, Suncor is planning to complete construction of an additional coker unit as part of its Millennium project, bringing an additional 97,000 Bpd of synthetic production to the market.

        The Athabasca Oil Sands Project, or AOSP, owned by Shell Canada Limited (60%), Chevron Canada Limited (20%) and Marathon Oil Corporation (20%), is another oil sands project that reached full production capacity in 2004. The AOSP project moved forward with AEUB's conditional approval of the proposed AOSP Expansion 1 project in 2006. The AOSP Expansion 1 project aims to achieve an expansion from the current production capacity of 158,000 Bpd of synthetic crude oil to more than 249,000 Bpd by 2010.

        Over the next two years, unblended bitumen production is expected to start, or increase, from more than ten individual projects that are coming on line. Notable projects include the expansions at Canadian Natural's Wolf Lake/Primrose area, ConocoPhillips' Surmont, Devon's Jackfish, EnCana's Foster Creek and Christiana Lake, Husky's Sunrise, Suncor's Firebag and Total's Josyln project. Based on the AEUB forecast, unblended bitumen production is expected to increase by roughly 38,000 Bpd by the end of 2008, more than offsetting the decline in conventional crude production.

        Although the crude oil and liquid petroleum delivered through the Lakehead system primarily originates in oilfields in western Canada, the Lakehead system also receives approximately five percent of its receipts from domestic sources including:

        Based on forecasted growth in western Canadian crude oil production and completion of upgrader expansions and increased bitumen production, Lakehead system deliveries are expected to average 1.69 million Bpd in 2008 compared with 1.54 million Bpd in 2007. The estimated deliveries for 2008 are

8


part of a forecast representing forward-looking information and are subject to risks, uncertainties, and factors beyond our control.

        Our ability to increase deliveries and to expand our Lakehead system in the future will ultimately depend upon numerous 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, and availability of markets for produced crude. Higher crude oil production from the WCSB should result in higher deliveries on the Lakehead system. Deliveries on the Lakehead system are also affected by periodic maintenance, turnarounds and other shutdowns at producing plants that supply crude oil to, or refineries that take delivery from, our Lakehead system.

        We expect the demand for WCSB crude oil production will continue to increase in PADD II. Refinery configurations and crude oil requirements in PADD II continue to be an attractive market for Western Canadian supply. According to the U.S. Department of Energy's Energy Information Administration, 2007 demand for crude oil in PADD II declined slightly from 2006 with an average of 3.2 million Bpd. At the same time, production of crude oil within PADD II increased marginally by 12,000 Bpd to 469,000 Bpd. With the proximity of the WCSB to PADD II, the availability of capacity on the Lakehead system and limited alternative markets for WCSB production, we expect deliveries on the Lakehead system to increase along with increases in WCSB supply. Based on our industry survey, we expect refineries in the PADD II market to compete aggressively with new markets for access to the growing supply of crude oil from the WCSB.

        In conjunction with Enbridge, we continue to progress on schedule with construction of the 400,000 Bpd Southern Access expansion project. We are undertaking the United States portion of the expansion on our Lakehead system. The first stage of construction is on schedule for completion in the first half of 2008 that will add approximately 190,000 Bpd. This stage of the project includes a new pipeline between Superior and Delavan, Wisconsin, along with pump station enhancements upstream and downstream of this segment. The second stage of the Southern Access expansion project will provide capacity and a new pipeline from Delavan to Flanagan, Illinois, with completion expected in the first half of 2009. Completion of the total Southern Access expansion project will create a 454-mile pipeline with approximately 400,000 Bpd of incremental capacity on our Lakehead system.

        On March 16, 2006, the Federal Energy Regulatory Commission ("FERC") approved an Offer of Settlement with respect to rate principles for the Southern Access expansion, which were negotiated with CAPP. In July 2006, support from shippers and CAPP was obtained to increase the diameter of the new pipeline segment of the project from 36 inches to 42 inches. The larger diameter will not provide increased capacity in the near term but does increase the ultimate expansion capacity of the line from 800,000 Bpd to 1,200,000 Bpd with additional pumping horsepower. This improves future expansion opportunities for our Lakehead system. In the interim, shippers will absorb all of the incremental operating costs of the larger diameter pipe but will benefit from reduced power costs at higher throughput levels.

        We anticipate the ultimate cost to complete our portion of the Southern Access project to approximate $2.1 billion. This estimate reflects our cost experience to date for labor, materials and rights-of-way. The risk to our unitholders resulting from any escalation of costs is largely mitigated by the cost of service tolling arrangement used for the project. Approximately 88 percent of cost overages will be included in the rate base, which forms the basis for determining our tariff rates for transportation. The remaining 12 percent of the project cost relates to installing larger pipe than required under current agreements, which we are financing in anticipation of future expansion opportunities.

        In July 2006, Enbridge announced that it had received support from shippers and CAPP for its 36-inch diameter, 400,000 Bpd Southern Access Extension pipeline from Flanagan, Illinois to Patoka, Illinois. The extension will broaden the reach of the Enbridge/Lakehead mainline system to incremental markets accessible from the Patoka hub. The project will be undertaken by Enbridge; however, we will benefit from

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the incremental volumes moving through our Lakehead system to connect with this extension. The initial FERC Offer of Settlement filed in September 2006 was rejected by the FERC due to the rolled in rate design contained in the Offer of Settlement. However, as a result of the strong support for the project, Enbridge filed a second application with the FERC in the latter half of 2007 with an alternative tolling structure to address the initial opposition from the intervening parties. A decision by the FERC is expected in early 2008 to allow the project to continue on schedule, with a 2009 in-service date.

        Forecasts of oil sands production growth developed by Enbridge, as well as by CAPP, indicate that additional export pipeline capacity out of Western Canada will be needed over and above projects currently under construction. As a result of these forecasts and support received from shippers, we and Enbridge are developing the Alberta Clipper project. This project involves construction of a 36-inch diameter 1,000 mile heavy crude oil pipeline from Hardisty, Alberta to Superior generally within or adjacent to our and Enbridge's existing rights-of-way. We will construct approximately 330 miles of the new pipeline from the International Border near Neche, North Dakota to Superior, and at the request of our customers, we have revised the scope to include a delivery connection at Clearbrook, Minnesota and an additional tank at Superior. Alberta Clipper will have an initial capacity of 450,000 Bpd and allows for expansions up to 800,000 Bpd by adding pumping stations. In addition, complementary capacity on the Southern Access 42-inch pipeline from Superior to Flanagan will be obtained by installing additional pump stations. We anticipate that our share of the construction cost for the United States segment of the project will approximate $1.0 billion (in 2007 dollars excluding capitalized interest). Alberta Clipper is expected to be in service by mid-2010.

        In May 2007, Enbridge filed an application with Canada's National Energy Board, or NEB, for the construction and operation of the Canadian segment of the project. In June 2007 Enbridge filed supplements to this application setting forth the tolling principles of the Canadian portion of the project, which are supported by CAPP and the hearings were concluded in the forth quarter of 2007. The United States regulatory and permit applications are in progress at state and federal levels. Enbridge is also progressing with land access, engineering and initial procurement commitments to facilitate commencement of project construction.

        In another effort to provide shippers access to new markets, Enbridge acquired a pipeline that runs from Chicago to Cushing. The pipeline, renamed Spearhead, began delivering Canadian crude oil to the major oil hub at Cushing in March 2006 and has operated at or near its capacity of 125,000 Bpd. We have benefited from Western Canadian crude oil being carried on our Lakehead system as far as Chicago, and then transferred to the Spearhead pipeline. On March 2, 2007, Enbridge initiated a binding open season for expansion of the pipeline to 190,000 Bpd, which was successfully concluded in late April with receipt of binding commitments for capacity in excess of 30,000 Bpd. Preliminary engineering design has been completed, and the expansion is expected to be completed by early 2009. This project will be complementary to our Lakehead system.

        In April 2006, ExxonMobil announced it had completed the reversal of two of its crude oil pipelines allowing up to 66,000 Bpd of Canadian crude oil to flow from Patoka, Illinois to the U.S. Gulf Coast. The pipeline is linked to our Lakehead system at Chicago via the Mustang Pipe Line Partners system to Patoka, Illinois. The Mustang system is 30% owned by an affiliate of Enbridge. ExxonMobil has received firm commitments from Canadian shippers for an average of 50,000 Bpd of capacity on the lines from Patoka, to Nederland, Texas for the next five years. The connection of our Lakehead system with this new market should also support increased throughput on our Lakehead system, although the reversed ExxonMobil system is also capable of transporting western Canadian crude oil moved via other competing pipelines into the Patoka market.

        In December 2007, Enbridge and ExxonMobil Pipeline Company announced that they will jointly conduct a Solicitation for Binding Shipper Commitment for a proposed new pipeline system, to transport crude oil from Patoka, Illinois, to the Texas Gulf Coast. The new pipeline, to be called the "Texas Access

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Pipeline," will transport crude oil sourced from the Canadian oil sands region in Alberta, Canada, and from the upper Midwest to refiners in the Nederland and Houston, Texas areas. The proposed project includes a new 768-mile, 30-inch diameter pipeline, which would transport crude oil from Patoka, Illinois, southward to Nederland, Texas. Also proposed is an 88-mile, 24-inch pipeline to transport crude oil onward from Nederland to a delivery point in the east Houston area. The Commitment Solicitation is for shipper interest in executing binding commitments to transport specified volumes of crude oil on the new pipeline, which is expected to be completed in 2011. The results of the Commitment Solicitation will guide and determine the further development of the proposed joint venture pipeline project.

        Competition.    Our Lakehead system, along with the Enbridge system, is the main crude oil export route from the WCSB. WCSB production in excess of western Canadian demand moves on existing pipelines into the Midwest area of the United States (PADD II), the Rocky Mountain states (PADD IV), the Anacortes area of Washington State (PADD V), and the U.S. 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 2007, the latest data available shows that PADD II total demand was 3.2 million Bpd while it produced only 469,000 Bpd, and thus imported 2.7 million Bpd. The latest available data for 2007 indicate PADD II imported approximately 1.1 million Bpd of crude oil from Canada, a majority of which was transported on our Lakehead system to destinations in PADD II and to other pipeline systems with PADD III destinations. The remaining 1.6 million Bpd was imported from PADDs III and IV as well as from offshore sources through the U.S. Gulf Coast. Lakehead system deliveries of Canadian crude oil to PADD II were level with delivery volumes for 2006. Total deliveries on our Lakehead system averaged 1.53 million Bpd in 2007, meeting approximately 71 percent of Minnesota refinery capacity; 60 percent of the greater Chicago area; and 67 percent of Ontario's refinery demand.

        Considering all of the pipeline systems that transport western Canadian crude oil out of Canada, the System transported approximately 67 percent of the total western Canadian crude oil exports in 2007 to the United States. The remaining production was transported by systems serving the British Columbia, PADD II, PADD IV, and PADD V markets.

        Given the expected increase in crude oil production from the Alberta oil sands over the next 10 years, alternative transportation proposals have been presented to crude oil producers. These proposals range from expansions of existing pipelines that currently transport western Canadian crude oil, to new pipelines and extensions of existing pipelines. These proposals are in various stages of development, with some at the concept stage and others that are proceeding with regulatory approval. Some of these proposals could be in direct competition with our Lakehead system.

        Enbridge has proposed construction of the Gateway Pipeline with an in-service date in the 2012 to 2014 timeframe, which includes both a condensate import pipeline and a petroleum export pipeline. The condensate line would transport imported diluent from Kitimat, British Columbia to the Edmonton, Alberta area. The petroleum export line would transport crude oil from the Edmonton area to Kitimat and would compete with our Lakehead system for production from the Alberta oil sands.

        We and Enbridge believe that the Southern Access Expansion Program, the Alberta Clipper Project, and other initiatives to provide access to new markets in the Midwest, Mid-continent and Gulf Coast, offer flexible solutions to future transportation requirements of western Canadian crude oil producers, and the in-service timing of these solutions is in line with prospective shipper needs.

        The following provides an overview of other proposals put forth by competing pipeline companies that are not affiliated with Enbridge:

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        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 beyond the Southern Access Expansion and Extension projects and the Alberta Clipper Project. They could also affect throughput on and utilization of the System. However, the Lakehead and Enbridge systems offer significant cost savings and flexibility advantages, which are expected to continue to favor the 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.

 
   Deliveries
 
   2007
   2006
   2005
   2004
   2003
 
   (thousands of Bpd)
United States                    
  Light crude oil   346   327   241   275   258
  Medium and heavy crude oil   852   872   791   785   741
  NGL   4   5   4   4   4
   
 
 
 
 
  Total United States   1,202   1,204   1,036   1,064   1,003
   
 
 
 
 
Ontario                    
  Light crude oil   184   160   146   174   174
  Medium and heavy crude oil   62   63   59   81   68
  NGL   95   90   98   103   109
   
 
 
 
 
  Total Ontario   341   313   303   358   351
   
 
 
 
 
Total Deliveries   1,543   1,517   1,339   1,422   1,354
   
 
 
 
 
Barrel miles (billions per year)   408   400   338   367   345
   
 
 
 
 

Mid-Continent system

        Our Mid-Continent system, which we acquired in the first quarter of 2004, is located within the PADD II district and is comprised of our Ozark pipeline, our West Tulsa pipeline and storage terminals at Cushing and El Dorado, Kansas. It includes over 480 miles of crude oil pipelines and 16.7 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. Our West Tulsa pipeline moves crude oil from Cushing to Tulsa, Oklahoma where it delivers to Sinclair Oil Corporation's Tulsa refinery.

        The storage terminals consist of 104 individual storage tanks ranging in size from 55,000 to 575,000 barrels. We added a net of 7 new tanks during 2007 to our existing storage facilities in Cushing, which increased our crude oil storage capacity to 16.7 million. 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 spot storage arrangements with its shippers. During 2007, approximately 40 shippers tendered crude oil for service by the 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 system were 236,000 Bpd for 2007 and 244,000 Bpd for 2006.

        Supply and Demand.    The Mid-Continent system is positioned to capitalize on increasing near-term demand for imported crude oil from west Texas and the U.S. Gulf Coast as well as third-party storage demand. In 2007, PADD II imported 2.7 million Bpd from outside of the PADD II region. The Lakehead system supplied roughly 1.1 million Bpd of crude from Canada leaving 1.6 million Bpd imported from PADDs III and IV as well as offshore sources. We expect the gap between local supply and demand for

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crude oil in PADD II to continue to widen, encouraging imports of crude oil from Canada, PADD III, and foreign sources.

        Competition.    Our Ozark pipeline system currently serves an exclusive corridor between Cushing and Wood River. However, refineries connected to Wood River have crude supply options available from Canada via the Lakehead system, with a connection to the Mustang pipeline, an Enbridge affiliated system, and through a third party pipeline, which runs from western Canada and PADD IV. These same refineries also have access to U.S. Gulf Coast and foreign supply through the Capline 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 through the Ozark system, also have access to west Texas supply through the Texas Gulf pipeline owned by unrelated parties. The Ozark pipeline system could face a significant increase in competition if a proposed new pipeline from Hardisty, Alberta to Patoka is completed in 2009. However, if that situation occurs, we would consider potential 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. With the reversal of the Spearhead pipeline, western Canadian crude oil moving on Spearhead 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.

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. Its crude oil gathering pipelines collect crude oil from points near producing wells in approximately 22 oil fields in North Dakota and Montana. Most deliveries from the North Dakota system are made at Clearbrook, Minnesota, to the Lakehead system and to a third-party pipeline system. The North Dakota system includes approximately 330 miles of crude oil gathering lines connected to a transportation line that is approximately 620 miles long, with a capacity of approximately 110,000 Bpd. We recently completed a 30,000 Bpd increase in capacity resulting from a $78.2 million expansion of the system we began in 2006 and completed in December 2007. This expansion was necessary to meet increased crude oil production from the Montana and North Dakota region. We have also proposed an approximate $150 million additional expansion to further increase system capacity to 161,000 Bpd. The commercial structure for this expansion is a cost-of-service based surcharge that will be added to the existing tariff rates. The proposed surcharge is similar to the structure being used on the recently completed expansion project and is subject to approval from the FERC. The North Dakota system also has 21 pump stations, one delivery station, and 11 terminaling facilities with an aggregate working storage capacity of approximately 745,000 barrels.

        Customers.    Customers of the North Dakota system include 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 largest integrated oil companies.

        Supply and Demand.    Like the Lakehead system, the 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.

        Competition.    Competitors of the 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

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fields served by the North Dakota system have alternative gathering facilities available to them or have the ability to build their own facilities.

Natural Gas Segment

        We own and operate natural gas gathering, treating, processing and transportation systems as well as trucking operations. We purchase and gather natural gas from the wellhead, 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 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, 2007, we have 10 active treating plants and 24 active processing plants, including three hydrocarbon dewpoint control facilities, or HCDP plants. Our treating facilities have a combined capacity exceeding 1,050 MMcf/d while the combined capacity of our processing facilities approximates 1,800 MMcf/d, including 550 MMcf/d provided by the HCDP plants.

        Our natural gas segment consists of the following systems:

        Customers.    Customers of our natural gas pipeline systems include both purchasers and producers of natural gas. Purchasers are comprised of marketers, including our Marketing business, and large users of natural gas, such as power plants, industrial facilities and local distribution companies. 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.

        Our natural gas pipelines serve customers predominantly in the Gulf Coast and southeastern regions of the United States. Customers include 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.

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        Supply and Demand.    Demand for our gathering, treating and processing services primarily depends upon the supply of natural gas reserves and the drilling rate of new wells. The level of impurities in the natural gas gathered also affects treating services. Demand for these services also depends upon overall economic conditions and the prices of natural gas and NGLs. Our larger systems, Anadarko, East Texas and North Texas, are located in basins that continue to experience growth in natural gas drilling and production.

        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, continues to experience substantial growth. Production in the Bossier trend has grown from under 390 MMcf/d in 1997 to over 1,500 MMcf/d in August 2007. During 2006, the link between our North Texas and East Texas systems became fully operational and increased the utilization of the 500 MMcf/d intrastate pipeline that we placed in service in June 2005 on our East Texas system by providing additional market access to customers of our North Texas system. In a further effort to address the continuing strong growth in natural gas production occurring in East Texas, in early 2006 we initiated a $635 million expansion and extension of our East Texas system named the Clarity project. During 2007, we completed the following segments of this expansion project:

We expect construction of the remaining segments that will connect natural gas supply from Bethel to Orange, Texas will be completed in the first quarter of 2008. Additional capacity to downstream interconnects will increase as compression is added through mid-2008. Completion of our Clarity project will provide service to major industrial companies in Southeast Texas with interconnects to interstate pipelines, intrastate pipelines and wholesale customers. We have firm volume commitments and acreage dedications which we believe will approximate 600 MMcf/d of the 700 MMcf/d of capacity by the end of 2008 and we continue to pursue additional commitments for capacity on the pipeline. The Clarity project is designed to be expandable and is positioned for potential upstream and downstream extension to meet the growing demand for natural gas transportation capacity.

        We have also completed significant expansion of our treating and processing capacity in the region, which began in 2006 with the completion of our 120 MMcf/d Henderson natural gas processing facility. We completed the following additional facilities during 2007:

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        The gathering, treating, processing and transportation assets we have placed in service over the past several years on our East Texas system are well positioned to capture the growing supply of natural gas being produced in the region as a result of the improved access to primary natural gas markets provided by our Clarity project.

        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 is one of the most 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, technological developments in fracturing the shale formation allows commercial production of these natural gas reserves. Based on the latest information available for 2007, Barnett Shale production has risen from approximately 110 MMcf/d in 1999 to over 2,900 MMcf/d in 2007, with the drilling of over 6,600 wells. We anticipate that throughput on the North Texas system will increase modestly in each of the next several years as a result of Barnett Shale development.

        Our Anadarko system is located within the Anadarko basin and continues to experience considerable growth as a result of the rapid development of the Granite Wash play in Hemphill and Wheeler counties in Texas. We have expanded our natural gas processing capacity to approximately 445 MMcf/d at the end of 2007, with the addition of the Hidetown processing facility with 120 MMcf/d of capacity. We also continue to add field compression to accommodate the volume growth on this system.

        We intend to expand our natural gas gathering and processing services primarily 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 for our existing assets.

        Our natural gas pipelines generally serve different geographical areas, with differing supply and demand characteristics in each market. We believe demand and competition for natural gas in the areas served by our natural gas assets will generally remain strong as a result of being located in areas where industrial, commercial or residential growth is occurring. The greatest demand for services in the markets served by our natural gas assets occurs in the winter months.

        The table below indicates the capacity in MMcf/d of the transportation and wholesale customer pipelines with firm transportation contracts and the amount of capacity that is reserved under those contracts as of that date.

Major System
   Capacity MMcf/d
   Percentage
Reserved Under
Contract as of
December 31, 2007
  
UTOS system   1,200   0 %
Midla system   200   74 %
AlaTenn system   200   28 %
Bamagas system   450   61 %

        Our UTOS system transports natural gas from offshore platforms on a fee for service basis to other pipelines onshore for further delivery and does not have long-term contracts. The average daily throughput on our UTOS system during 2007 was 192,000 MMBtu/d. The FERC approved our negotiated settlement with UTOS shippers, keeping our current rates in effect under our 2003 FERC Order, through 2006. In February 2007, the FERC approved our application for an extension of that Order to keep the settlement rates in effect for an additional 3-year term through 2009.

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        Our Midla, AlaTenn and Bamagas systems primarily serve industrial corridors and power plants in Louisiana, Alabama and Tennessee. Industries in the area include energy intensive segments of the petrochemical and pulp and paper industries. We market the unused capacity on these systems under both short-term firm and interruptible transportation contracts and long-term firm transportation contracts. These systems are located in areas where opportunities exist to serve new industrial facilities and to make delivery interconnects to alleviate capacity constraints on other third-party pipeline systems. As of December 31, 2007, approximately 74 percent of contracted capacity of the Midla system and approximately 15 percent of the AlaTenn system is under contract to our marketing business. We recently initiated negotiations with a major customer of our Midla mainline transmission system for the renewal of a contract that is set to expire in August 2008. Although the ultimate outcome of these negotiations is uncertain, we may incur a non-cash impairment charge for this asset, if the customer elects not to renew the contract, or renews the contract on less favorable terms. We are also exploring alternative uses for this pipeline system.

        The Bamagas system in northern Alabama is contiguous with our AlaTenn system and serves two power plants that are indirectly owned by Calpine Corporation ("Calpine"). In December 2005, Calpine Corporation ("Calpine") and many of its subsidiaries, including the subsidiary that owns the two utility plants served by our Bamagas system, filed voluntarily petitions to restructure under Chapter 11 of the United States Bankruptcy Code. Since filing for bankruptcy, Calpine has continued to perform under the terms of its agreements with Bamagas. In June 2007, Calpine and certain of its subsidiaries filed a Joint Plan of Reorganization and Disclosure Statement with the United States Bankruptcy Court. On December 19, 2007, the U.S. Bankruptcy Court for the Southern District of New York issued a decision confirming Calpine's reorganization plan. In addition, the Bamagas contracts with Calpine have been reaffirmed. Calpine announced at the end of January 2008 that it has emerged from Bankruptcy.

        Our long-term financial condition depends on the continued availability of natural gas for transportation to the markets served by our systems. Existing customers may not extend their contracts if the availability of natural gas from the Mid-continent and Gulf Coast producing regions was to decline and if the cost of transporting natural gas from other producing regions through other pipelines into the areas we serve were to render the delivered cost of natural gas uneconomical. We may be unable to find additional customers to replace the lost demand or transportation fees.

        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 gas systems, such as our East Texas system, competition is more limited due to the infrastructure required to treat sour gas.

        Competition for customers in the marketing of residue gas is based primarily upon the price of the delivered gas, the services offered by the seller and the reliability of the seller in making deliveries. Residue 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

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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, a number of new interstate natural gas pipelines are being constructed in areas currently served by some of our intrastate and interstate pipelines. When completed, these new pipelines may compete for customers with our existing pipelines.

        We also include our trucking and liquids marketing operations in our Natural Gas segment. Trucking and liquids marketing operations include the transportation of NGLs, crude oil and carbon dioxide by truck and railcar from wellheads and treating, processing and fractionation facilities and to wholesale customers, such as distributors, refiners and chemical facilities. In addition, our trucking and liquids 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 43% of the volume transported by our trucking and liquids marketing business and is a major source of its growth in this area.

        Our services are provided using trucks, trailers and rail cars, product treating and handling equipment and NGL storage facilities. In addition, our CO2 plant, with 250 tons per day of capacity, takes excess CO2 from hydrogen producers which we then sell to a variety of customers. We also have 50% ownership of an underground propane storage facility in Petal, Mississippi, which augments the services we provide to our customers in the region. The total capacity of this facility is 5.6 million Bbls which increases our storage capabilities.

        We have increased the size of our truck fleet by approximately 25 percent since 2005 to meet the growing supply of NGLs, crude oil and carbon dioxide from our processing facilities, as well as to capitalize on the opportunity to better serve our Gulf Coast customers.

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

        Supply and Demand.    The areas served by our trucking and liquids marketing operations are geographically diverse, and the forces that affect the supply of the products transported vary by region. Crude oil and natural gas prices and production levels affect the supply of these products. The demand for 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 liquids 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 liquids 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 mitigate financial risk and maximize the value of the natural gas purchased by our gathering systems and the throughput on our gathering and intrastate wholesale customer pipelines. 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, Oklahoma, Alabama, Mississippi and Louisiana, the majority of activities conducted by our Marketing segment are focused within these areas.

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        Customers.    Natural gas purchased by our Marketing segment 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 segment. 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. Marketing pays third-party storage facilities and pipelines for the right to store gas for various periods of time. These contracts may be denoted as firm storage, interruptible storage, or parking and lending services. These various contract structures are used to mitigate risk associated with sales and purchase contracts, and to take advantage of price differential opportunities. Due to the increased volumes from our gathering assets, our Marketing business leases third-party pipeline capacity downstream from our Natural Gas assets under firm transportation contracts following specific, controlled guidelines. 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 gas producers, independent aggregators and regional marketing companies.

REGULATION

FERC Allowance for Income Taxes in Interstate Common Carrier Pipeline Rates

        In a 1995 decision involving our Lakehead system, which we refer to as the Lakehead ruling, the FERC partially disallowed the inclusion of income taxes in the cost of service for the Lakehead system. In its Lakehead ruling, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. A subsequent appeal of the Lakehead ruling was resolved by settlement and therefore was not adjudicated. In another FERC proceeding involving Santa Fe Pacific Pipeline, L.P. (SFPP), an unrelated pipeline entity, the FERC initially relied on its previous Lakehead ruling to hold that SFPP could not claim an income tax allowance for income attributable to non-corporate partners, both individuals and other entities. SFPP and other parties to the proceeding appealed the FERC's orders to the United States Court of Appeals for the District of Columbia Circuit, or the D.C. Circuit Court.

        In a decision issued in July 2004, in BP West Coast Products, LLC v. FERC, which we refer to as the BP West Coast decision, the D.C. Circuit Court vacated the portion of the FERC decision regarding the proper tax allowance for SFPP and remanded the case to the FERC for further proceedings.

        In May and June 2005, the FERC issued a policy statement, as well as an order on remand of BP West Coast (the SFPP order), respectively, in which it stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline's owners have such actual or potential income tax liability will be determined by the FERC on a case-by-case basis. The new policy entails rate risk due to the case-by-case review requirement.

        In December 2005, the FERC issued its first case-specific review of the income tax allowance issue reaffirming its income tax allowance policy and directing the pipeline to provide certain evidence necessary to determine its income tax allowance. The FERC's BP West Coast remand decision and the new tax allowance policy were appealed to the D.C. Circuit Court.

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        In May 2007, the D.C. Circuit Court upheld the income tax allowance policy adopted by the FERC for master limited partnerships (MLPs) and other non-taxable entities. On the basis of the SFPP order, the D.C. Circuit Court concluded that the FERC's new policy statement applied to SFPP and resolved the principle defect of the Lakehead policy, which was the inadequately explained differential treatment of the tax liability of the individual and corporate partners. On that basis the D.C. Circuit Court affirmed the FERC's tax allowance policy as being reasonable and in accordance with the FERC's statutory discretion. As such, the D.C. Circuit Court affirmed that an allowance should be permitted on all partnership interests, or similar legal interest, if the owner of that interest has an actual or potential income tax liability on the public utility income earned though the interest. We believe all our applicable assets will be entitled to a tax allowance to the extent a pipeline's partners have income tax liability on the income they receive from the pipeline. In August 2007, the D.C. Circuit Court denied a request for rehearing of its May 2007 decision, and the decision is now final and cannot be appealed.

        In December 2006, the FERC issued a new order addressing rates on one of the interstate oil pipelines of SFPP. In that order, the FERC addressed challenges to the policy statement raised by shippers in filings in another docket earlier in 2006. In the new order, the FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. The FERC noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which the FERC characterized as a "tax savings." The FERC stated that it is concerned that this creates an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, the FERC chose to adjust the pipeline's equity rate of return downward based on the percentage by which the publicly traded partnership's cash flow exceeded taxable income. On February 7, 2007, SFPP asked the FERC to reconsider this ruling. The ultimate outcome of this proceeding is not certain and could result in changes to the FERC's treatment of income tax allowances in cost of service rates and to potential adjustment in a future rate case of our pipelines' respective equity rates of return that underlie their rates to the extent that cash distributions in excess of taxable income are allowed to some unitholders. If the FERC were to disallow a substantial portion of our pipelines' income tax allowance, it may cause our rates to be set at a level that is different, and in some instances lower, than the level otherwise in effect.

FERC Regulation of Return on Equity for Master Limited Partnerships

        On July 19, 2007, the FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate returns on equity for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of MLPs in the proxy group for purposes of calculating returns on equity under the Discounted Cash Flow (DCF) analysis, a change from its prior view that MLPs had not been shown to be appropriate for such inclusion. Specifically, the FERC proposes that MLPs may be included in the proxy group provided that the DCF analysis recognizes as distributions only the pipeline's reported earnings, and not other sources of cash flow subject to distribution. According to the proposed policy statement, under the DCF analysis, the return on equity is calculated by adding the dividend or distribution yield (dividends divided by share/unit price) to the projected future growth rate of dividends or distributions (weighted one third for long-term growth of the economy as a whole and two-thirds short term growth as determined by analysts' five-year forecasts for the pipeline). The determination of which MLPs should be included will be made on a case by case basis, after a review of whether an MLP's earnings have been stable over a multi-year period. The FERC proposes to apply the final policy statement to all pipeline rate cases that have not completed the hearing phase as of the date the FERC issues the final policy statement and has requested comments on the proposed policy which were due in September 2007. The FERC's proposed policy statement is subject to change based on comments filed and therefore we cannot predict the scope of the final policy statement.

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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's Office of Pipeline Safety. The order took effect on January 1, 2006. Under the order, FERC-regulated companies are generally required to recognize costs incurred in performing pipeline assessments that are part of a pipeline integrity management program as 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.

        We have historically 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 will continue to expense secondary internal inspection tests consistent with our previous practice. Refer to Note 2—Summary of Significant Accounting Policies included in our consolidated financial statements beginning at page F-1 of this annual report on Form 10-K for additional discussion.

Regulation by the FERC of Interstate Common Carrier Liquids Pipelines

        The 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. As common carriers in interstate commerce, these pipelines provide service to any shipper who requests transportation services, provided that products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The ICA generally 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 charge for service on our interstate common carrier pipelines. The ICA requires, among other things, that such rates be "just and reasonable" as well as nondiscriminatory. The ICA permits interested persons 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, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund with interest the increased 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.

        On October 24, 1992, Congress passed the Energy Policy Act of 1992, or 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 has determined that the 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.

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We believe that the rates for the North Dakota and Ozark systems should be found to be largely covered by the grandfathering provisions of the EP Act.

        The EP Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines, and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561, which, among other things, adopted an indexing rate methodology for petroleum pipelines. Under the 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 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.

        Under Order No. 561, the original inflation index adopted by the FERC was equal to the annual change in the Producer Price Index for Finished Goods, or PPI-FG, minus one percentage point. The index was subject to review every five years. Rates were then subject to an annual adjustment, based upon changes in the PPI-FG minus 1%, in order to accurately reflect the actual cost changes experienced by the oil pipeline industry. In December 2000, as part of the FERC's five-year review of the oil-pricing index (July 2001 through June 2006), the FERC concluded that the PPI-FG accurately reflected the actual cost changes experienced by the industry. In February 2003 the FERC issued an Order on Remand concluding that for the current five-year period, the oil-pricing index should be the PPI-FG. In order to calculate the 2003 ceiling rate levels, oil pipelines were permitted to use the PPI-FG adjustment as though it had been in effect since 2001. As of July 1, 2007, the index increased to equal PPI-FG plus 1.3 percentage points, resulting in an index of 4.3186% for the period of July 1, 2007 through June 30, 2008.

Regulation by the FERC of Interstate Natural Gas Pipelines

        Our AlaTenn, Midla and UTOS systems are interstate natural gas pipelines regulated by the FERC under the Natural Gas Act, or NGA, and the Natural Gas Policy Act, or NGPA. Each system operates under separate FERC-approved tariffs that establish rates, terms and conditions under which each system provides service to its customers. Natural gas companies may not charge rates that have been determined not to be just and reasonable. In addition, the FERC's authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce includes:

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        The maximum recourse rates that may be charged by our pipelines for their services are established through the FERC's ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline's actual prudent historical cost investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline's FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline's profitability. Our interstate pipelines are permitted to discount their firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not "unduly discriminate."

        Tariff changes can only be implemented upon approval by the FERC. Two primary methods are available for changing the rates, terms and conditions of service of an interstate natural gas pipeline. Under the first method, the pipeline voluntarily seeks a tariff change by making a tariff filing with the FERC justifying the proposed tariff change and providing notice, generally 30 days, to the appropriate parties. If the FERC determines that a proposed change is just and reasonable as required by the NGA, the FERC will accept the proposed change and the pipeline will implement such change in its tariff. However, if the FERC determines that a proposed change may not be just and reasonable as required by the NGA, then the FERC may suspend such change for up to five months beyond the date on which the change would otherwise go into effect and set the matter for an administrative hearing. Subsequent to any suspension period ordered by the FERC, the proposed change may be placed into effect by the company, pending final FERC approval. In most cases, a proposed rate increase is placed into effect before a final FERC determination on such rate increase, and the proposed increase is collected subject to refund (plus interest). Under the second method, the FERC may, on its own motion or based on a complaint, initiate a proceeding seeking to compel the company to change its rates, terms and/or conditions of service. If the FERC determines that the existing rates, terms and/or conditions of service are unjust, unreasonable, unduly discriminatory or preferential, then any rate reduction or change that it orders generally will be effective prospectively from the date of the FERC order requiring this change.

        In November 2003, the FERC issued Order 2004 governing the Standards of Conduct for Transmission Providers (including natural gas interstate pipelines). These standards provide that interstate pipeline employees engaged in natural gas transmission system operations must function independently from any employees of their energy affiliates and marketing affiliates and that an interstate pipeline must treat all transmission customers, affiliated and non-affiliated, on a non-discriminatory basis, and cannot operate its transmission system to benefit preferentially, an energy or marketing affiliate. In addition, Order 2004 restricts access to natural gas transmission customer data by marketing and other energy affiliates and provides certain conditions on service provided by interstate pipelines to their gas marketing and energy affiliates. We have implemented changes in business processes to comply with this order. In November 2006, the D.C. Circuit Court vacated Order 2004 as that order applies to interstate natural gas pipelines and remanded that proceeding to the FERC for further action.

        On January 9, 2007, the FERC issued Order 690 in response to the D. C. Circuit Court's decision. In its Order, the Commission issued new interim standards of conduct pending the outcome of a new rulemaking proceeding. The interim standards will only govern the relationship between an interstate pipeline and its marketing affiliates as opposed to its energy affiliates, the latter being a much broader category as originally set forth in Order 2004. As a result, the Commission effectively "repromulgated" on a temporary basis the Standards of Conduct first issued in Order 497 in 1992, while it considers its course of action to address the court's decision on a more permanent basis.

        On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking ("NOPR") in Docket No. RM07-1 wherein it proposes to make permanent its interim standards of conduct issued in Order 690. The Commission is also seeking comment as to whether it should make comparable changes to the electric industry standards of conduct that were not affected by either the November 2006 decision by the D.C.

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Circuit Court, or by Order 690, as well as comments regarding certain other electric-related exceptions to Order 2004. We continue to closely monitor these proceedings and administer our compliance programs accordingly.

        On September 20, 2007, the FERC issued a Notice of Inquiry regarding Fuel Retention Practices of Natural Gas Pipelines (Fuel NOI). The Fuel NOI inquires whether the current policy which allows natural gas pipelines to choose between two options for recovering the costs of fuel and lost and unaccounted for (LAUF) gas should be changed in favor of a uniform method. Comments have been filed in response to the Fuel NOI. The outcome of this proceeding could result in changes to the methodology used by our pipelines for calculating fuel and LAUF gas, which could potentially affect the pipelines' revenues.

        On September 20, 2007, the FERC issued a Notice of Proposed Rulemaking regarding Revisions to Forms, Statements, and Reporting Requirements for Natural Gas Pipelines (Reporting NOPR). The Reporting NOPR proposed to require pipelines to (i) provide additional information regarding their sources of revenue and amounts included in the rate base; (ii) identify costs related to affiliate transactions; and (iii) provide additional information regarding incremental facilities, and discounted and negotiated rates. According to the FERC, changes would assist pipeline customers and other third parties in analyzing a pipeline's actual return as compared with its approved rate of return based on publicly filed data. Although the FERC proposed that the changes would be effective January 1, 2008, the final rule has not been issued. The FERC's proposed rulemaking is subject to change based on comments filed and therefore we cannot predict the scope of the final rulemaking.

        On November 15, 2007, the FERC issued a notice of proposed rulemaking proposing to permit market-based pricing for short-term capacity releases and to facilitate asset management arrangements by relaxing the FERC's prohibition on tying and on its bidding requirements for certain capacity releases (Capacity Release NOPR). The FERC proposes to lift the price ceiling for short-term capacity release transactions of one year or less. The Capacity Release NOPR is proposed to enable releasing shippers to offer competitively-priced alternatives to pipelines' negotiated rates and to encourage more efficient construction of capacity. Under the FERC's proposal, it is possible for the releasing shipper to release the natural gas at market-based prices while our pipelines would still be subject to the maximum rate cap. The FERC's proposed rulemaking is subject to change based on comments filed and therefore we cannot predict the scope of the final rulemaking.

        On December 21, 2007, the FERC issued a notice of proposed rulemaking which proposes to require interstate natural gas pipelines and certain non-interstate natural gas pipelines to post capacity, daily scheduled flow information, and daily actual flow information. Comments are due on March 13, 2008, and a technical conference will be held regarding these issues on April 3, 2008. Adoption of this proposal by the FERC could result in additional administrative burdens and could result in increased capital costs.

        Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated; therefore, there is no assurance that a more stringent regulatory approach will not be pursued by the FERC and Congress, especially in light of potential market power abuse by marketing affiliates of certain pipeline companies engaged in interstate commerce. In response to this issue, Congress, in the Energy Policy Act of 2005 ("EPACT"), and the FERC have implemented requirements to ensure that energy prices are not impacted by the exercise of market power or manipulative conduct. EPACT prohibits the use of any "manipulative or deceptive device or contrivance" in connection with the purchase or sale of natural gas, electric energy or transportation subject to the FERC's jurisdiction. The FERC then adopted the Market Manipulation Rules and the Market Behavior Rules to implement the authority granted under EPACT. These rules, which prohibit fraud and manipulation in wholesale energy markets, are very vague and are subject to broad interpretation. Only two orders interpreting these rules have been issued to date, and each of these is subject to further proceedings. These orders reflect the FERC's view that it has broad latitude in determining whether specific behavior violates the rules. In addition, EPACT gave the FERC

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increased penalty authority for these violations. The FERC may now issue civil penalties of up to $1 million per day for each violation of the FERC's rules, and there are possible criminal penalties of up to $1 million and 5 years in prison. Given the FERC's broad mandate granted in EPACT, it is assumed that if energy prices are high, or exhibit what the FERC deems to be "unusual" trading patterns, the FERC will investigate energy markets to determine if behavior unduly impacted or "manipulated" energy prices.

Intrastate Pipeline Regulation

        Our intrastate liquids and natural gas pipeline operations generally are not subject to rate regulation by the FERC, but they are subject to regulation by various agencies of the states in which they are located. However, to the extent that our intrastate pipeline systems deliver natural gas into interstate commerce, the rates, terms and conditions of such transportation service are subject to the FERC's jurisdiction under Section 311 of the NGPA, which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline making deliveries on behalf of a local distribution company or an interstate natural gas pipeline. Most states have agencies that possess the authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Some states also have state agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers.

Natural Gas Gathering Pipeline Regulation

        Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain natural gas pipelines that we believe meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but historically has not entailed rate regulation. In 2005, the FERC initiated an inquiry regarding the extent to which gathering (both offshore and onshore) systems, particularly those that have been previously transferred from a regulated entity should be regulated by the FERC. The FERC terminated this inquiry in early 2007 without making any finding that would expand its existing regulatory purview over gathering facilities. Further, some states have, or are considering, providing greater regulatory scrutiny over the commercial regulation of 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 and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities.

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.

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        Our sales of crude oil, condensate and natural gas liquids 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 border crossing points require U.S. government permits that may be terminated or amended at the will of the U.S. Government. These permits provide that pipelines may be inspected by or subject to orders issued by federal or state government agencies.

Tariffs and Rate Cases

Lakehead system

        Under published tariffs at December 31, 2007 (including the tariff surcharges related to Lakehead system expansions) for transportation on the Lakehead system, the rates for transportation of heavy crude oil from Neche, North Dakota, where the System enters the United States (unless otherwise stated), to principal delivery points are set forth below.

 
   Published
Tariff Per Barrel
To Clearbrook, Minnesota   $ 0.2279
To Superior, Wisconsin     0.4562
To Chicago, Illinois area     0.9585
To Marysville, Michigan area     1.1496
To Buffalo, New York area     1.1769
Chicago to the international border near Marysville     0.4118

        The rates at December 31, 2007 for light and medium crude oils and NGLs are lower than the rates set forth in the table to compensate for differences in the costs of shipping different types and grades of liquid hydrocarbons. We periodically adjust our tariff rates as allowed under the FERC's indexing methodology and the tariff agreements described below.

Base Rates:

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

SEP II Surcharge:

        Under the Settlement Agreement with CAPP that the FERC approved in 1996 and reconfirmed in 1998, we implemented a tariff surcharge related to our SEP II project. This tariff surcharge, which is added to the base rates, is a cost-of-service based calculation that is trued-up annually (usually in April) for actual costs and throughputs 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.

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Terrace Surcharge:

        Under the Tariff Agreement approved by the FERC in 1998, we also implemented a tariff surcharge for the Terrace expansion program of approximately $0.013 per barrel for light crude oil from the Canadian border to Chicago. On April 1, 2001, pursuant to an agreement between us and Enbridge Pipelines Inc. our share of the surcharge was increased to $0.026 per barrel. This surcharge was in effect until April 1, 2004, when our share of the surcharge changed to $0.007 per barrel. Our share will remain at this level until 2010, after which time the surcharge will return to $0.013 per barrel through 2013, the term of the agreement. In addition to the Terrace surcharge, included in our tariff is the Terrace Schedule C adjustment. Under the tariff agreement, when Terrace Phase III facilities are in service, and annual actual average pumping exiting Clearbrook are less than 225,000 M3 per day, an adjustment is made to the Terrace surcharge. In 2007, this adjustment is $0.061 per barrel, based on annual actual average pumpings exiting Clearbrook of 197,861 M3 per day in 2006.

Facilities Surcharge:

        On July 1, 2004, the FERC approved a settlement with CAPP involving a Facilities Surcharge mechanism, which allows for the recovery of costs for enhancements or modifications to the system at shipper request and approved by CAPP. The Facilities Surcharge permits 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. Like the SEP II surcharge, the Facilities Surcharge is a cost-of-service-based tariff mechanism that is trued-up each year for actual costs and throughput and, therefore, is not subject to adjustment either upwards or downwards under indexing. In 2007, the Facilities Surcharge was $0.012 per barrel for light movements from the international border near Neche, North Dakota to Chicago. The Facilities Surcharge currently includes four projects that were agreed to with CAPP in 2004. Additional projects to be included in the Facilities Surcharge will be determined as the result of a negotiating process between management of the Lakehead system and CAPP.

        On March 16, 2006, the FERC approved the Offer of Settlement we filed on December 21, 2005, seeking approval for the Southern Access mainline expansion surcharge under the provisions of the previously approved Facilities Surcharge mechanism. The Southern Access mainline expansion centers on the construction of a new 42-inch diameter pipeline between Superior, Wisconsin and Flanagan, Illinois, along with associated upstream modifications to balance the expanded capacity created by the new Superior-to-Flanagan line.

        On September 1, 2006, Enbridge filed an Offer of Settlement with the FERC seeking prompt approval for the Southern Access Extension surcharge. The proposed Extension is a new 36-inch pipeline which connects with the Southern Access Mainline Expansion pipeline at Flanagan to Patoka, Illinois, which allows Canadian producers and shippers to access the Patoka hub, where they can then access other refining centers. Under the framework that established the Facilities Surcharge already approved by the Commission, the proposed tolling methodology in the Offer of Settlement asked that the costs for the Extension be added to the existing base rates as a surcharge. A variety of benefits would accrue to shippers through the Extension, including a reduction in total tariff rates due to the higher utilization of upstream facilities and therefore reducing the net cost to shippers even if they do not ship on the Extension itself. The Offer of Settlement was opposed by three shippers and was rejected by the Commission on December 8, 2006, which stated that Enbridge did not submit adequate proof that the proposed pipeline would benefit all shippers.

        On October 18, 2007, Enbridge filed a Petition for Declaratory Order with the FERC seeking approval for a revised tariff structure on the Extension and associated surcharges and surcredits on the Lakehead system. The proposed tariff methodology in this petition is a stand alone cost-of-service rate from Flanagan to Patoka, Illinois. However, in the first few years of operation, it is not clear that the

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pipeline will be able to attract sufficient volumes to recover all of its costs. Thus, a backstopping mechanism with the Lakehead system has been proposed for the pipeline system. In the event that a deficiency occurs for a given year, this deficiency would be recovered from Lakehead mainline shippers. Any surpluses would then be credited back to Lakehead shippers in the form of rate credits until the cumulative deficiency, including interest is eliminated. The term of the agreement is for fifteen years. Enbridge/Lakehead mainline shippers will enjoy various benefits as a result of the expansion. Several parties have filed letters of support of the Declaratory Order, and the Petition has been opposed by one shipper. Enbridge has requested a decision from the FERC by February 2008.

Mid-Continent system

        The Mid-Continent system is comprised of pipeline, terminaling, and storage infrastructure located in the U.S. Mid-continent region. Specifically the system originates in Cushing, Payne County, Oklahoma and offers transportation service to Wood River, Madison County, Illinois; West Tulsa, Oklahoma, other Mid-Continent system facilities, local area refineries, and other interconnected non-affiliated pipeline infrastructure. The rates for the transportation of light crude oil from Cushing, Payne County, Oklahoma to principle delivery points are set forth below:

 
   Published
Tariff Per Barrel
To Wood River, Illinois   $ 0.4587
To West Tulsa, Oklahoma   $ 0.1926

        The rates at December 31, 2007, outlined above, apply to light crude only. Medium and heavy crude oil transportation rates on these systems are higher to compensate us for differences in the costs of shipping different types and grades of liquid hydrocarbons. In addition to the routes above, we also have the following two joint tariffs—one with All American Pipeline, L.P., which allows for transportation from points in Texas and Jal, New Mexico, to Wood River, Illinois, and another with Koch Pipeline Company, L.P., which allows for transportation from Cushing, Oklahoma, to Hartford Tankage, Illinois.

        Where applicable, we periodically adjust our tariff rates as allowed under the FERC's indexing methodology. Currently, this methodology allows for an adjustment of rates equal to the PPI-FG + 1.3%, which adjustment is made effective July 1 of each year.

North Dakota system

        Our North Dakota system consists of both gathering and trunk line assets. All gathering rates in effect at December 31, 2007, from points in North Dakota and Montana are $0.6350 per barrel. Effective January 1, 2008, two new surcharges were implemented as a part of the Phase V expansion. In August 2006, we submitted an Offer of Settlement to the FERC for an expansion of the pipeline system, which was approved by the Commission on October 31, 2006 (Docket No. OR06-9-000). The Offer of Settlement outlined the mainline expansion and looping surcharges as cost-of-service based surcharges that will be trued up each year to actual costs and are not subject to the FERC indexing methodology. These surcharges are applicable for the five years immediately following the in-service date of the Phase V expansion, which we placed in service in January 2008. The mainline expansion surcharge is applied to all transportation routes with a destination of Clearbrook, Minnesota, beginning January 1, 2008. The looping surcharge is applied to all routes originating at Trenton and Alexander, North Dakota. The rates and

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surcharges for transportation of light crude oil to principle delivery points via trunk lines on our North Dakota System are set forth below:

 
   Published(1)
Tariff Per Barrel
at December 31,
2007
   Surcharge(2)
Per Barrel
   Revised Tariff
Per Barrel
effective
January 1,
2008
From Glenburn, Haas, Lignite, Minot, Newburg, Sherwood, Stanley and Wiley, North Dakota to Clearbrook, Minnesota   $ 0.7721   $ 0.1434   $ 0.9155
From Brush Lake and Dwyer, Montana and Grenora, North Dakota to Clearbrook, Minnesota   $ 0.8841   $ 0.1434   $ 1.0275
From Clear Lake, Dagmar, Flat Lake and Reserve, Montana to Clearbrook, Minnesota   $ 0.9089   $ 0.1434   $ 1.0523
From Tioga, North Dakota to Clearbrook, Minnesota   $ 0.7967   $ 0.1434   $ 0.9401
From Trenton and Missouri Ridge, North Dakota to Clearbrook, Minnesota to Clearbrook, Minnesota   $ 1.0088   $ 0.6170   $ 1.6258
From Alexander, North Dakota to Clearbrook, Minnesota   $ 1.0460   $ 0.6170   $ 1.6630
From Brush Lake, Dagmar and Clear Lake, Montana to Tioga, North Dakota   $ 0.4857     —   $ 0.4857
From Reserve, Montana to Tioga, North Dakota   $ 0.5479     —   $ 0.5479
From Trenton and Missouri Ridge, North Dakota to Tioga, North Dakota   $ 0.4609   $ 0.4736   $ 0.9345
From Alexander, North Dakota to Clearbrook, Minnesota   $ 0.4978   $ 0.4736   $ 0.9714
(1)
Pursuant to FERC Tariff No. 48 as filed with the FERC on May 30, 2007, with an effective date of July 1, 2007.

(2)
Pursuant to FERC Tariff No. 53 as filed with the FERC on November 30, 2007, with an effective date of January 1, 2008.

        The rates outlined above, are subject to adjustment as allowed under the indexing methodology established by the FERC. Currently this methodology allows for an adjustment of rates equal to the PPI-FG +1.3%, which is made effective July 1 of each year. In addition to the routes above, we have a joint tariff with Plains Pipeline, L.P., which allows for transportation from points in Richland and McCone counties in Montana to Tioga, North Dakota and Clearbrook, Minnesota.

Natural Gas Systems

        Tariff rates on the FERC-regulated natural gas pipelines are approved by the FERC and vary by pipeline depending on a number of factors, including cost of providing service, throughput levels on the pipeline, and other factors. Competitive forces may prompt us to charge tariff rates below the FERC-approved maximum rate on our interstate systems. The rates charged for transmission of natural gas on pipelines not regulated by the FERC, or a state agency, are established by competitive forces.

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Safety Regulation and Environmental

General

        Our transmission and gathering pipelines and storage and processing facilities 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 non-rural gathering pipelines are subject to regulation by the United States Department of Transportation, or DOT, Pipeline and Hazardous Materials Safety Administration ("PHMSA") under Title 49 United States Code (Pipeline Safety Act, or PSA) relating to the design, installation, testing, construction, operation, replacement and management of transmission and non-rural gathering pipeline facilities. The PHMSA is the agency charged with regulating the safe transportation of hazardous materials under all modes of transportation, including intrastate pipelines. Periodically the PSA has been reauthorized and amended, imposing new mandates on the regulator to promulgate new regulations, imposing direct mandates on operators of pipelines.

        On December 17, 2002, the PSI Act of 2002 was enacted reauthorizing and amending the PSA. The most significant amendment required natural gas pipelines to develop integrity management programs and conduct integrity assessment tests at a minimum of seven year intervals. Such tests can include internal inspection, hydrostatic pressure tests or direct assessments on pipelines in certain high consequence areas. The PHMSA has since promulgated rules for this and other mandates included in the PSI Act of 2002.

        On December 29, 2006, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (PIPES of 2006) was signed into legislation that further amended the Pipeline Safety Act. Many of the provisions were welcome, including strengthening excavation damage prevention and enforcement. The most significant provisions of PIPES of 2006 that will affect us, but not materially, 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.

        We have incorporated the new requirements of the 2002 and 2006 PSA amendments into procedures and budgets and, while we expect to incur higher regulatory compliance costs, the increase is not expected to be material.

        The Pipeline Safety Act Reauthorization of 2006 (PIPES Act) required, among other measures, for PHMSA to extend their current jurisdictional authority to regulate previously exempted low operating stress pipelines. In September 2007, the PHMSA issued a Notice of Proposed Rulemaking that details how such low stress pipelines would be regulated and the safety measures that would be required. Industry commented and PHMSA is expected to issue the Final Rule early in 2008. The Final Rule is expected to have regulatory requirements that will not materially affect our low stress transmission pipelines.

        When hydrocarbons are released into the environment, the PHMSA can impose a return-to-service plan, which can include implementing certain internal inspections, pipeline pressure reductions, and other strategies to verify the integrity of the pipeline in the affected area. We do not anticipate any return-to-service plans that will have a material impact on system throughput or compliance costs; however we have the potential of incurring expenditures to remediate any condition in the event of a discharge or failure on our systems.

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        Our trucking and railcar operations are also subject to safety and permitting regulation by the DOT and state agencies with regard to the safe transportation of hazardous and other materials.

        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 expenses 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 which 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 leaks or spills of crude oil, liquids or 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 certain capital expenses in the next several years for air pollution control equipment and spill prevention measures in connection with maintaining existing facilities and obtaining permits and approvals for any new or acquired facilities.

        The Oil Pollution Act (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 leak. 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,

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the OPA regulations are promulgated by the Environmental Protection Agency, or EPA. We believe 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.

        Employee Health and Safety.    The workplaces associated with our operations are subject to the requirements of the federal Occupational Safety and Health Administration, or OSHA, and comparable state statutes that regulate worker health and safety. We have an ongoing safety, procedure and training program for our employees and believe that our operations are in compliance with applicable OSHA requirements, including industry consensus standards, record keeping requirements, monitoring of occupational exposure to regulated substances, and hazard communication standards.

        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, 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 government agencies where appropriate.

EMPLOYEES

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

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INSURANCE

        Our operations are subject to many hazards inherent in the liquid petroleum and natural gas gathering, treating, processing and transportation industry. We maintain insurance coverage for our operations and properties considered to be customary in the industry. Our coverage limits for property and business interruption, general liability, and pollution liability insurance are expressed in Canadian dollars, or CAD, and range from $400 million CAD to $650 million CAD, representing $404.8 million to $657.8 million in United States dollars (USD) at December 31, 2007 based on the exchange rate of $1.0120 USD = $1 CAD at this date. Insurance policy deductibles are stated in CAD and vary with coverage. As expressed in USD our deductibles are approximately $10.2 million, $0.1 million, and $2.5 million for property, general liability, and pollution liability, respectively, which have been converted from CAD based on the exchange rate presented above. 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, 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 file annual, quarterly and other reports, and any amendments to those reports, and information with the Securities and Exchange Commission, or SEC, under the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act. You may read and copy any materials that we file with the SEC at the SEC's Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including ours.

        We also make available free of charge on or through our Internet website http://www.enbridgepartners.com our Annual Report 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 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 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 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:

        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 and competition can reduce the utilization of our Lakehead system. For example, in January 2005, deliveries on our Lakehead system were impacted by a fire at a Suncor facility. The volume of crude oil that we transport on the Lakehead system also depends on the demand for crude oil in the Great Lakes and Midwest regions of the United States and the delivery by others of crude oil and refined products 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 the 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, Canada. Furthermore, full utilization of additional capacity as a result of our current and future expansions of the Lakehead system, including the Southern Access project, will largely depend on these anticipated increases in crude oil production from oil sands projects. The government of the Province of Alberta has adopted measures to increase its share of revenues from oil sands development. These measures could cause oil sands producers to cancel or delay plans to expand their facilities, which, in turn, would reduce the volume growth we have anticipated in executing our construction projects to increase the capacity of our crude oil pipelines.

        The volume of shipments on natural gas systems depends on the supply of natural gas and NGLs available for shipment on those systems from the producing regions that supply these systems. Volumes

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shipped on these systems also are 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 the Mid-continent, 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 was 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.

        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 might 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 delay 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. Some producing states, including Oklahoma and Texas, are considering legislation that would require rate and/or service regulation of gathering and intrastate transmission natural gas systems. Increased state regulation could adversely impact our natural gas systems.

        The question of whether and to what extent an income tax allowance should be included in a regulated utility's cost of service for rate-making purposes was a matter of uncertainty for a number of years. On May 29, 2007, the D.C. Circuit Court denied petitions for review of the FERC's income tax allowance ("ITA") policy. The D.C. Circuit Court, which previously vacated and remanded prior FERC orders on the subject, affirmed the ITA policy that the FERC adopted in its May 4, 2005, Policy Statement on Income Tax Allowances, 111 FERC ¶ 61,139 ("Policy Statement"), which concluded that "such an allowance should be permitted on all partnership interests, or similar legal interests, if the owner of that interest has an actual or potential income tax liability on the public utility income earned through the interest," thereby extending the ITA to both corporations and partnerships (or other pass-through entities). In addition, the FERC's Policy Statement contemplates that individual rate proceedings will determine "whether a particular partner... has an actual or potential income tax liability, and what assumptions, if any, should determine the amount of the related tax rate..."

        A related issue is whether the FERC's Policy Statement can be relied upon by shippers as a substantial change in circumstances sufficient to remove the grandfathering protection under the EP Act from an oil pipeline's rates. As part of its May 29, 2007 opinion, the D.C. Circuit Court denied the petitions for review with respect to the EP Act issues and upheld the FERC's interpretation of the EP Act as reasonable.

        We believe that the rates we charge for transportation services on our interstate common carrier pipelines are just and reasonable under the ICA and NGA. However, because the rates that we charge are subject to review upon an appropriately supported protest or complaint, we cannot predict what rates we will be allowed to charge in the future for service on our interstate common carrier 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.

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        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 revenues. 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, Illinois; Detroit, Michigan; Toledo, Ohio; Buffalo, New York; and Sarnia, Ontario 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 could face a significant increase in competition if a proposed new pipeline from Hardisty, Alberta to Patoka is completed in 2009. However, if that situation occurs, we would consider potential alternative uses for our Ozark system.

        We also encounter competition in our natural gas gathering, treating, processing, and transmission businesses. A number of new interstate natural gas transmission pipelines being constructed could reduce the revenue we derive from the interstate and intrastate transmission of natural gas. Many of the large wholesale customers served by our systems' transmission and wholesale customer pipelines 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 and/or from third parties that may hold capacity on other pipelines. For example, our Midla system is currently negotiating the renewal of a contract with one of its primary customers that is set to expire in August 2008, and could result in a contract with less favorable terms. Other systems such as our AlaTenn system face similar competition. Likewise, 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 certain 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:

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

        We buy and sell natural gas and NGLs in connection with our marketing activities. Commodity price exposure is also inherent in gas purchase and resale activities and in gas processing. 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. Further, hedging contracts are subject to the credit risk that the other party may prove unable or unwilling to perform its obligations under such contracts. 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.

        Compliance with environmental and operational safety regulations, including any remediation of soil or water pollution or hydrostatic testing of our pipeline systems, may increase our costs and/or reduce our revenues.

        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. Liquid petroleum and natural gas transportation and processing operations always involve the risk of costs or liabilities or operational modifications related to regulatory compliance as well as resulting from historical environmental contamination, accidental releases or upsets, regulatory enforcement, litigation or safety and health incidents. As a result, we may incur costs or liabilities of this type, or experience a reduction in revenues, in the future. We may also establish temporary pressure restrictions on some sections of our pipelines pending completion of specific inspection and renewal programs. Pressure restrictions reduce the available capacity of the applicable line segment and could result in a loss of throughput and related revenue if and when the full capacity of that line segment would otherwise have been utilized. We may also incur costs in the future due to changes in environmental and safety laws and regulations, enforcement policies or claims for personal, property or environmental damage. We may not be able to recover these costs from insurance or through higher tariffs.

        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. A casualty occurrence might result in injury or loss of life or extensive property or environmental damage for which we may bear a part or all of the cost.

        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 or are unable to raise financing on acceptable terms.

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

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        In addition, we may be unable to identify acquisition targets and consummate acquisitions in the future or be unable to raise, on terms we find acceptable, any debt or equity financing that may be required for any such acquisition.

        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 increase cash distributions.

        Our strategy contemplates significant expenditures for the development, construction or other acquisitions of energy infrastructure assets. Increased demand for the steel used to fabricate the pipe needed for our construction projects and increased competition for labor has resulted in increased costs for these resources. As a result, we may not be able to complete our projects at the costs currently estimated or within the time periods we have projected. If we experience material cost overruns, we will have to finance these overruns using one or more of the following methods:

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

        Our revenues and cash flows may not increase immediately on our expenditure of funds on a particular project. For example, if we build a new pipeline or expand an existing facility, the design, construction, development and installation may occur over an extended period of time and we may not receive any material increase in revenue or cash flow from that project until after it is placed in service and customers begin using the systems. 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.

        Measurement losses on our pipeline system can be materially impacted by changes in estimation, commodity prices and other factors.

        Oil measurement losses occur as part of the normal operating conditions associated with our liquid petroleum pipelines. The three types of oil measurement losses include:

        Quantifying oil measurement losses is inherently difficult because physical measurements of volumes are not practical due to the fact that products constantly 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 size and scope of our pipeline systems and the number of different grades of crude oil and types of crude oil products we carry. Accordingly, we utilize engineering-based models and operational assumptions to estimate product volumes in our system and associated oil measurement losses.

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        Natural gas measurement losses occur as part of the normal operating conditions associated with our natural gas pipelines. The quantification and resolution of measurement losses 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 losses that can occur on our natural gas systems.

        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 partners 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 delegee, 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.

        We are exposed to credit risks of our customers

        Some of our customers may experience financial problems that could have a significant affect 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. For example, in December 2005, Calpine and many of its subsidiaries, including the subsidiary that owns two utility plants served by our Bamagas system, filed voluntarily petitions to restructure under Chapter 11 of the United States Bankruptcy Code. Our Bamagas system is the sole supplier of natural gas to these two utility plants, which exposed us to a potential asset impairment for the book value of the pipeline, if the customer was unable to fulfill its commitments. Financial problems experienced by our customers may also reduce or curtail their future use of our products and services, which could reduce our revenues.

        Canada's ratification of the Kyoto Protocol may adversely impact our operations.

        In December 2002, Canada ratified the Kyoto Protocol, a 1997 treaty designed to reduce greenhouse gas emissions to 6% below 1990 levels. We and Enbridge are monitoring the Canadian federal government's approach to implementation. While the United States is not a signatory to the Kyoto Protocol, other environmental protection initiatives have been implemented regulating certain priority pollutants. Revisions have been proposed to the U.S. Energy Act that would, if passed, expand the regulation of certain greenhouse gas emissions requiring a cap and establishing a trade to facilitate compliance. While proposed legislation has not yet passed and as other legislation is being proposed the outcome is uncertain at this time. If and when these provisions pass the Partnership could be subject to additional costs to monitor and control emissions above and beyond current practices and permits.

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

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

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

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

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

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

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

        In other situations, Enbridge may take certain actions, including engaging in businesses that compete with us, 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:

        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, Ontario to Montreal, Quebec. As a result of this reversal, Enbridge competes with us to supply crude oil to the Ontario, Canada 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 and the issuance of additional Class C units, other than our quarterly distributions to you, may have the following effects:

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        Additionally, the public sale by our general partner of a significant portion of the Class B common units or Class C 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 B common units or Class C units currently held by our general partner could absorb some of the trading market demand for the outstanding 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 subsidiary's ability to make distributions to us.

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

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

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

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.

        Our primary operating subsidiary is prohibited by its First Mortgage Notes from making distributions to us, and we are prohibited from making distributions to us other than cash distributions, and it may make cash distributions to us only if (1) the distribution amount does not exceed the current available cash of that subsidiary, (2) a default does not exist under the First Mortgage Notes after giving effect to the distribution and (3) timely notice of the distribution has been give to the Note holders. In addition, we are

43


prohibited from making distributions to our unitholders during (1) the existence of certain defaults under our Credit Facility 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 Facility and our subsidiary's First Mortgage Notes may prevent us from engaging in transactions or capitalizing on business opportunities that we believe could be beneficial to us by requiring us to comply with various covenants, including the maintenance of certain financial ratios and restrictions on:

        Although the indentures governing our senior notes do not limit our ability to incur additional debt, they impose restrictions on our ability to enter into mergers or consolidations and sales of all or substantially all of our assets, to incur liens to secure debt and to enter into sale and leaseback transactions. A breach of any restriction under our credit facility or our indentures or our subsidiary's First Mortgage Notes 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 Facility, 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

        We may be classified as an association taxable as a corporation rather than as a partnership, which would substantially reduce the value of our Class A common units.

        We could be treated as a corporation for United States income tax purposes. Our treatment as a corporation would substantially reduce the cash distributions on the common units that we distribute quarterly. Moreover, treatment of us as a corporation could materially and adversely affect our ability to make payments on our debt securities. The anticipated benefit of an investment in our common units depends largely on the treatment of us as a partnership for federal income tax purposes. Under current law, we are treated as a partnership for federal income tax purposes and do not pay any federal income tax at the entity level. In order to qualify for this treatment, we must derive more than 90% of our annual gross income from specified investments and activities. While we believe that we currently do qualify and intend to meet this income requirement, we may not find it possible, regardless of our efforts, to meet this income requirement or may inadvertently fail to meet this income requirement. 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. If we were to be treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and would pay state income taxes at varying rates. Under current law, distributions to unitholders would generally be taxed as a corporate distribution. Because a tax would be imposed upon us as a corporation, the cash available for distribution to a unitholder would be substantially reduced. Treatment of us as a corporation would cause a substantial reduction in the value of our units.

        In addition, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation similar to recent tax legislation in Texas and Michigan. State tax legislation resulting in the imposition of a partnership-level income tax on us could reduce the cash distributions we make on the Class A and B common units and the number of i-units and Class C units that we will distribute quarterly. The enactment of significant legislation imposing partnership-level income taxes could cause a reduction in the value of our Class A common units.

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        If the Internal Revenue Service does not respect our curative tax allocations, the after-tax return to our unitholders on their investment in our Class A common units would be adversely affected.

        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 Internal Revenue Service, which we refer to as 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 tax liability of our unitholders could exceed their distributions or proceeds from sales of Class A common units.

        The holders of our Class A common units will be required to pay United States 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. They will not necessarily receive cash distributions equal to the tax on their allocable share of our taxable income. Further, if we have a large amount of nonrecourse liabilities, they may incur a tax liability that is greater than the money they receive when they sell their Class A common units.

        A unitholder may be required to file tax returns with and pay income taxes to the states where we or our subsidiaries own property and conduct business.

        In some cases, a unitholder may be required to file income tax returns with and pay income taxes to the states in which we or our subsidiaries own property and conduct business, which are currently Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, New York, South Carolina, North Carolina, North Dakota, Oklahoma, Tennessee, Texas and Wisconsin. In the future, we may acquire property or do business in other states or in foreign jurisdictions. In addition to tax liabilities to such state and foreign jurisdictions, the owner of a Class A common unit may also incur tax and filing responsibilities to localities within such jurisdictions.

        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, including employee benefit plans, individual retirement accounts, Keogh plans and other retirement plans, regulated investment companies and foreign persons raises issues unique to them. Virtually all of the income derived from our Class A common units by a tax-exempt entity will be "unrelated business taxable income" and will be taxable to the tax-exempt entity. Further, a unitholder who is a nonresident alien, a foreign corporation or other foreign person will be required to file a federal income tax return and pay tax on his share of our taxable income because he will be regarded as being engaged in a trade or business in the United States as a result of his ownership of a Class A common unit.

        Our registration with the Secretary of the Treasury as a "tax shelter" may increase your risk of an IRS audit.

        Because we are a registered "tax shelter" with the Secretary of the Treasury, a unitholder may face an increased risk of an IRS audit resulting in taxes payable on our income as well as income not related to us. We could be audited by the IRS and adjustments to our income or losses could be made. Any unitholder owning less than a 1% profit interest in us has very limited rights to participate in the income tax and audit process. Further, any adjustments in our tax returns will lead to adjustments in the unitholders' tax returns and may lead to audits of unitholders' tax returns and adjustments of items unrelated to us. Each unitholder is responsible for any tax owed as the result of an examination of their personal tax return.

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        We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the 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 the general partner, which may be unfavorable to such unitholders. Moreover, 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.

        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.

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

        The IRS may challenge the manner in which we calculate our unitholder's basis adjustment under Internal Revenue Code Section 743(b). If so, because neither we nor a unitholder can identify the Class A Common Units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all unitholders selling Class A Common Units within the period under audit as if all unitholders owned Class A Common Units with respect to which allowable deductions were not taken. Any position we take that is inconsistent with applicable Treasury regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our unitholders. It also could affect the 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 without the benefit of additional deductions.

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Item 1B. Unresolved Staff Comments

        None.


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 or permits that have been granted by private land owners, public authorities, railways or public utilities. The pumping stations, tanks, terminals and certain other facilities of our systems are located on land that is owned by us, except for five pumping stations that are situated on land owned by others and used by us under easements or permits.

        Substantially all of our Lakehead system assets are subject to a first mortgage lien collateralizing indebtedness of our Lakehead Partnership.

        Titles to our properties acquired in the Midcoast system acquisition 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.


Item 4. Submission of Matters to a Vote of Security Holders

        No matters were submitted to a vote of security holders during the fourth quarter of 2007.

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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 2007 and 2006 are summarized as follows:

 
   First
   Second
   Third
   Fourth
2007 Quarters                        
High   $ 56.23   $ 61.82   $ 58.47   $ 54.16
Low   $ 48.25   $ 52.30   $ 48.27   $ 48.71
Cash distributions paid   $ 0.925   $ 0.925   $ 0.925   $ 0.950

2006 Quarters
 
 
 
 
 
 
 
 
 
 
 
 
High   $ 47.80   $ 44.80   $ 49.51   $ 50.99
Low   $ 42.88   $ 42.00   $ 43.26   $ 46.10
Cash distributions paid   $ 0.925   $ 0.925   $ 0.925   $ 0.925

        On February 20, 2008 the last reported sales price of our Class A common units on the NYSE was $50.99. At February 12, 2008, there were approximately 80,000 Class A common unitholders, of which there were approximately 1,600 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, our Class C units, which are held by the General Partner and institutional investors, or our i-units, all of which are held by Enbridge Management.

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Item 6. Selected Financial Data

        The following table sets forth, for the periods and at the dates indicated, our summary historical financial data. The table is derived, and should be read in conjunction with, our audited consolidated financial statements and notes thereto beginning at page F-1. See also "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

 
   Year ended December 31,
  
 
   2007
   2006
   2005
   2004
   2003
  
 
   (dollars in millions, except per unit amounts)

  
Income Statement Data:(2)(3)(4)                                
  Operating revenue   $ 7,282.6   $ 6,509.0   $ 6,476.9   $ 4,291.7   $ 3,172.3  
  Operating expenses     6,963.8     6,122.1     6,285.0     4,054.5     2,978.0  
   
 
 
 
 
 
  Operating income     318.8     386.9     191.9     237.2     194.3  
  Interest expense     99.8     110.5     107.7     88.4     85.0  
  Rate refunds     —     —     —     (13.6 )   —  
  Other income     3.0     8.5     5.0     3.0     2.4  
  Income tax expense     5.1     —     —     —     —  
   
 
 
 
 
 
  Income from continuing operations   $ 216.9   $ 284.9   $ 89.2   $ 138.2   $ 111.7  
   
 
 
 
 
 
  Income from continuing operations per limited partner unit (basic and diluted)(1)   $ 2.08   $ 3.62   $ 1.06   $ 2.06   $ 1.93  
   
 
 
 
 
 
  Cash distributions paid per unit   $ 3.725   $ 3.700   $ 3.700   $ 3.700   $ 3.700  
   
 
 
 
 
 

Financial Position Data (at year end):(2)(3)(4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Property, plant and equipment, net   $ 5,554.9   $ 3,824.9   $ 3,080.0   $ 2,778.0   $ 2,465.6  
  Total assets     6,891.6     5,223.8     4,428.4     3,770.7     3,231.8  
  Long-term debt, excluding current maturities     2,862.9     2,066.1     1,682.9     1,559.4     1,155.8  
  Loans from General Partner and affiliates     130.0     136.2     151.8     142.1     133.1  
  Partners' capital:                                
    Class A common units     1,340.7     1,141.7     1,142.4     1,021.6     914.9  
    Class B common units     72.9     67.6     67.2     66.7     64.2  
    Class C units     874.1     509.8     —     —     —  
    i-units     515.3     466.3     421.7     399.4     370.7  
  General Partner     62.9     47.6     34.6     31.0     27.5  
  Accumulated other comprehensive loss     (294.4 )   (189.6 )   (302.1 )   (120.8 )   (64.0 )
   
 
 
 
 
 
  Partners' capital   $ 2,571.5   $ 2,043.4   $ 1,363.8   $ 1,397.9   $ 1,313.3  
   
 
 
 
 
 

Cash Flow Data:(2)(3)(4)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Cash flows provided by operating activities   $ 463.4   $ 321.6   $ 267.1   $ 245.4   $ 148.2  
  Cash flows used in investing activities     1,765.0     867.0     437.1     419.1     431.0  
  Cash flows provided by financing activities     1,167.5     640.2     181.5     187.6     286.9  
  Additions to property, plant and equipment and acquisitions included in investing activities, net of cash acquired     1,980.2     897.7     531.2     429.8     423.5  

Notes to Selected Financial Data:

(1)
The allocation of net income to the General Partner in the following amounts has been deducted before calculating income per unit: 2007, $37.7 million; 2006, $30.9 million; 2005, $23.5 million; 2004, $22.5 million; and 2003, $19.6 million.

(2)
Our income statement, financial position and cash flow data reflect the following acquisitions and dispositions:

•
April 2006, acquisition of a natural gas pipeline in east Texas;

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(3)
Our income statement, financial position and cash flow data include the effect of the following debt issuances:

•
The December 2007 issuance of $130 million note payable to Enbridge Hungary Ltd. and the simultaneous repayment of a $145 million note payable to Enbridge Hungary Ltd., including $8.8 million of accrued interest.

•
The September 2007 issuance of $400 million of junior subordinated notes;

•
The August 2007 issuance of $200 million of zero coupon senior unsecured notes and $3.6 million of accreted interest;

•
The April 2007 amendment of our credit facility, which increased the maximum principal amount of credit available to us at any one time from $1 billion to $1.25 billion, allows us to request increases in the maximum principal amount of credit available at any one time from $1.25 billion to $1.5 billion, eliminates the letter of credit sublimit and extends the maturity to 2012;

•
The December 2006 issuance of $300 million of senior unsecured notes;

•
The September 2005 amendment of our credit facility to extend the letter of credit sublimit from $175 million to $300 million and increase the commitments available from $600 million to $800 million maturing in 2010, and the subsequent extension of the commitments available to $1 billion in March 2006.

•
The April 2005 establishment of a $600 million commercial paper program;

•
The December 2004 issuance of $300 million of senior unsecured notes;

•
The April 2004 amendment of our credit facilities to terminate the 364-day revolving credit facility and increase the Three-year term credit facility to $600 million maturing in 2007;

•
The January 2004 issuance of $200 million of senior unsecured notes; and

•
The May 2003 issuance of $400 million of senior unsecured notes.

(4)
Our income statement, financial position and cash flow data include the effect of the following limited partner unit issuances:

•
The May 2007 issuance of 5.3 million Class A common units;

•
The April 2007 issuance of approximately 5.9 million Class C units to institutional investors;

•
The August 2006 issuance of approximately 10.8 million Class C units in equal amounts to our general partner and an institutional investor;

•
The December 2005 issuance of 0.13 million Class A common units; the November 2005 issuance of 3.0 million Class A common units; and the February 2005 issuance of 2.5 million Class A common units;

•
The September 2004 issuance of 3.68 million Class A common units; and the January 2004 issuance of 0.45 million Class A common units;

•
The December 2003 issuance of 5.0 million Class A common units; and the May 2003 issuance of 3.9 million Class A common units;

•
The quarterly in-kind distributions of 0.9 million, 1.0 million, 0.8 million, 0.8 million and 0.8 million i-units during 2007, 2006, 2005, 2004 and 2003 respectively, in lieu of cash distributions;

•
The quarterly in-kind distributions of 1.1 million and 0.2 million Class C units during 2007 and 2006, respectively, in lieu of cash distributions.

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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 on page F-1 of this Annual Report on Form 10-K.

RESULTS OF OPERATIONS—OVERVIEW

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

        We conduct our business through 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:

 
   2007
   2006
   2005
  
 
   (in millions)

  
Operating Income                    
  Liquids   $ 207.1   $ 199.8   $ 127.3  
  Natural Gas     91.2     133.9     110.5  
  Marketing     24.0     56.1     (42.4 )
  Corporate, operating and administrative     (3.5 )   (2.9 )   (3.5 )
   
 
 
 
Total Operating Income     318.8     386.9     191.9  
  Interest expense     (99.8 )   (110.5 )   (107.7 )
  Other income     3.0     8.5     5.0  
  Income taxes     (5.1 )   —     —  
   
 
 
 
  Income from continuing operations     216.9     284.9     89.2  
  Income from discontinued operations     32.6     —     —  
   
 
 
 
Net Income   $ 249.5   $ 284.9   $ 89.2  
   
 
 
 

        Several types of arrangements in our Natural Gas and Marketing segments expose us to market risk associated with changes in commodity prices where we receive natural gas or NGLs in return for the services we provide, or where we purchase natural gas or NGLs. We employ derivative financial instruments to reduce our exposure to natural gas and NGL prices. Some of these derivative financial instruments do not qualify for hedge accounting under the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), 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 financial instrument.

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Summary Analysis of Operating Results

        Our Liquids segment includes the operations of our Lakehead, North Dakota and Mid-Continent systems. Each of these systems largely consists of FERC-regulated interstate crude oil and liquid petroleum pipelines. The Lakehead system, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. Each of these systems generates most of its revenues by charging shippers a per barrel tariff rate to transport and store crude oil and liquid petroleum.

        Our Liquids segment contributed operating income of $207.1 million in 2007, or $7.3 million more than the $199.8 million contributed in 2006. The operating income of our Liquids segment in 2007 was affected by the following factors:

        Our Natural Gas segment consists of natural gas gathering and transmission pipelines, including three FERC-regulated interstate natural gas transmission pipelines, as well as natural gas treating and processing plants and related facilities. The revenues of our Natural Gas segment are derived from the fees we charge to gather and process natural gas and the rates we charge to transport natural gas on our pipelines.

        Operating income from our Natural Gas segment declined to $91.2 million in 2007 from $133.9 million in 2006, a decrease of $42.7 million. The operating results of our Natural Gas segment are attributable to the following:

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        Our Marketing segment provides supply, transmission, storage and sales services to producers and wholesale customers on our 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.

        Operating income from our Marketing segment decreased $32.1 million to $24.0 million in 2007 from $56.1 million for the comparable period in 2006. The change in operating income of our Marketing segment from 2007 to 2006 resulted from the following:


Derivative Transactions and Hedging Activities

        We record all financial instruments in our consolidated financial statements at fair market value pursuant to the requirements of SFAS No. 133. For those derivative financial instruments that do not qualify for hedge accounting, we record all changes in fair market value through our consolidated statements of income each period. The fair market value of our derivative financial instruments reflects the estimated amounts that we would pay or receive to terminate or close the contracts at the reporting date, although that is not our intent.

        Rising NGL prices coupled with relatively stable natural gas prices produced $62.8 million of unrealized, non-cash mark-to-market net losses from hedges of our optional NGL production during the year ended December 31, 2007. We also incurred $1.4 million of unrealized, non-cash mark-to-market losses during 2007 in connection with interest rate swaps that do not qualify for hedge accounting treatment under SFAS No. 133. During the fiscal year ended December 31, 2006, declining natural gas prices produced non-cash mark-to-market net gains of $64.4 million and positively affected our operating results. Mark-to-market gains or losses create volatility in our operating results although the derivative financial instruments we have in place do not affect our cash flow until they are settled. We expect these non-cash gains and losses to reverse in future periods as we settle the derivative financial instruments against the underlying physical transactions. We intend to continue using derivative financial instruments to hedge our portfolio of natural gas and NGLs because of the economic benefit we derive from minimizing the volatility in our cash flows. Our continued use of derivative financial instruments may result in additional unrealized, non-cash gains or losses in the future.

        The following table presents the unrealized gains and losses associated with changes in the fair value of our derivatives, which are recorded as an element of "Cost of natural gas" or in "Interest expense" in

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our consolidated statements of income and disclosed as a reconciling item on our consolidated statements of cash flows:

 
   Year ended December 31,
  
Derivative fair value gains (losses)
  
  2007
   2006
   2005
  
 
   (in millions)

  
Natural Gas segment                    
  Hedge ineffectiveness   $ —   $ (1.9 ) $ (2.5 )
  Non-qualified hedges     (59.0 )   1.8     (5.6 )
Marketing                    
  Non-qualified hedges     (3.8 )   64.5     (41.3 )
  Discontinued hedges     —     —     (9.0 )
   
 
 
 
  Commodity derivative fair value gains (losses)     (62.8 )   64.4     (58.4 )
Corporate                    
  Non-qualified interest rate hedges     (1.4 )   —     —  
   
 
 
 
Derivative fair value gains (losses)   $ (64.2 ) $ 64.4   $ (58.4 )
   
 
 
 

De-designation and Settlement of Derivatives

        In connection with the sale of assets in December 2005, as discussed in Note 3 to the consolidated financial statements beginning on page F-1 of this report, we settled for cash of approximately $16.3 million, natural gas collars representing derivative financial instruments on sales of 2,000 MMBtu/d of natural gas through 2011. We had previously recorded unrealized losses associated with the natural gas collars that were realized upon settlement. Additionally, we de-designated derivative financial instruments that qualified for and were designated as cash flow hedges of forecasted sales of 273 Bpd of NGLs through 2007 and contemporaneously closed out the position by entering into an offsetting derivative financial instrument, at market, on forecasted purchases of 273 Bpd of NGLs through 2007.

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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:

 
   Year Ended December 31,
 
   2007
   2006
   2005
 
   (dollars in millions)
Operating Results                  
Operating revenues   $ 548.1   $ 512.8   $ 418.0
   
 
 
Operating and administrative     156.1     141.3     144.2
Power     117.0     107.6     74.8
Depreciation and amortization     67.9     64.1     71.7
   
 
 
Operating expenses     341.0     313.0     290.7
   
 
 
Operating Income   $ 207.1   $ 199.8   $ 127.3
   
 
 

Operating Statistics
 
 
 
 
 
 
 
 
 
Lakehead system:                  
  United States(1)     1,202     1,204     1,036
  Province of Ontario(1)     341     313     303
   
 
 
  Total deliveries(1)     1,543     1,517     1,339
   
 
 
  Barrel miles (billions)     408     400     338
   
 
 
  Average haul (miles)     725     722     692
   
 
 
Mid-Continent system deliveries(1)     236     244     236
   
 
 
North Dakota system:                  
  Trunkline(1)     91     85     79
  Gathering(1)     7     7     8
   
 
 
North Dakota system deliveries(1)     98     92     87
   
 
 
Total Liquids Segment Delivery Volumes(1)     1,877     1,853     1,662
   
 
 
(1)
Average barrels per day in thousands.

Year ended December 31, 2007 compared with year ended December 31, 2006

        Our Liquids segment accounted for $207.1 million of operating income in 2007, representing an increase of $7.3 million over 2006. The favorable results of our Liquids business reflect modest growth in our transportation volumes while actively managing the costs of our services. The majority of this increase related to improved results on our Lakehead system.

        Operating revenue for the year ended December 31, 2007 increased by $35.3 million to $548.1 million from $512.8 million for the same period in 2006. The increase in revenue is primarily attributable to the higher delivery volumes on our Lakehead and North Dakota systems combined with the increase in average tariffs associated with the annual index rate increase that went into effect July 1, 2007, for all three of our liquids systems. We increased the transportation rates on our Lakehead system by an average of 4.5 percent and on our Ozark and North Dakota systems by an average of 4.3 percent. Additionally, new tariffs went into effect April 1, 2007, on our Lakehead system to reflect the annual calculation of the

55


SEP II and other surcharges based on true-ups of prior year amounts and estimates for 2007, as well as an adjustment for the Terrace surcharge due to lower than expected volumes moving on the Lakehead system in 2006. The tariff increases of our Liquids systems contributed approximately $15 million to the increase in our revenues for the year ended December 31, 2007.

        Also contributing to the increase in revenues for the year ended December 31, 2007, was a $5 million increase in contract storage fees generated by our Mid-Continent storage terminal system from the additional storage tanks we placed in service during 2007 and in late 2006. Across our Mid-Continent system, we added a net of seven storage tanks during 2007 contributing an additional 3.8 million barrels of capacity bringing the total storage capacity to approximately 16.7 million barrels and 104 tanks. This additional storage capacity is expected to provide ongoing fixed, variable, and spot storage revenue.

        Average delivery volumes on our Liquids systems increased to 1.877 million Bpd for the year ended December 31, 2007, from the 1.853 million Bpd during the same period in 2006, accounting for approximately $9 million of the increase in the operating revenues of our Liquids segment. The increase in average deliveries on our Liquids systems are primarily derived from modest production increases of Western Canadian crude oil delivered on our Lakehead system. The increase in deliveries is attributable to the following:

        Operating and administrative expenses for the year ended December 31, 2007 were $156.1 million, or $14.8 million greater than the $141.3 million for the same period in 2006. The increase in these costs is primarily attributable to the following:

        Our general partner charges us the costs associated with employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative services. The portion of compensation and related costs we are charged is dependent upon such items as estimated time spent, miles of pipe and headcount. We have experienced an increase in workforce related costs as a result of the growth and expansion of our Liquids system operations. We expect these costs will continue to increase in future periods as we continue to expand our Liquids system operations. The increase in operating and administrative costs is partially offset by a reduction for field inventory expenses we realized in 2006 that we did not incur in 2007.

        Our pipeline systems consist of individual pipelines of varying ages from approximately 60 years to newly constructed. With appropriate inspection and maintenance the physical life of a pipeline is indefinitely long. However, as our pipelines age we anticipate that the level of expenditures required for inspection, renewal and maintenance will increase. In addition, we have established temporary pressure restrictions on some sections of some of our pipelines pending completion of specific inspection and renewal programs, and may from time to time establish further temporary pressure restrictions. Pressure restrictions reduce the available capacity of the applicable line segment and could result in a loss of

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throughput if and when the full capacity of that line segment would otherwise have been utilized. The loss of throughput to date, resulting from pressure restrictions, has not materially affected our operating results.

        Oil measurement adjustments occur as part of the normal operations associated with our Liquids systems. The three types of oil measurement adjustments that normally occur on our systems include:


        We identified operating conditions in 2005 on a connected third-party facility that contributed to higher levels of physical losses. We have addressed the operating conditions causing these higher levels of physical losses, which have subsequently reduced the physical losses we have experienced on our Lakehead system. We are seeking to recover damages for the losses we sustained from the owner of the third-party system, but can make no assurances that we will be successful in our efforts.

        Power costs increased $9.4 million in 2007, compared with 2006, predominantly due to the higher utility rates we are charged by our power suppliers. The increase in delivery volumes is also a factor contributing to the additional power costs. We have experienced a trend of increasing electricity rates from our power suppliers due to higher natural gas costs.

Year ended December 31, 2006 compared with year ended December 31, 2005

        Our Liquids segment accounted for $199.8 million of operating income in 2006, representing an increase of $72.5 million over 2005. The favorable results of the Liquids segment assets reflect continuing growth in our transportation volumes while actively managing the costs of our services. The majority of this increase related to significantly improved results on our Lakehead system.

        Operating revenue in 2006 increased by $94.8 million to $512.8 million, compared with $418.0 million in 2005. As indicated in the table above, total delivery volumes of our Liquids segment averaged 1.853 million Bpd in 2006, representing a 0.191 million Bpd increase from the 1.662 million Bpd delivered in 2005. This accounted for an increase in operating revenues of approximately $48.0 million. The increases in deliveries on our Liquids systems are primarily derived from increased production of Western Canadian crude oil delivered on our Lakehead system. The increases in deliveries are attributable to the following:

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        Contributing to the revenue growth of our Liquids segment are the increases in the average tariffs on all three of our Liquids systems. These tariff increases were partly the result of the annual index rate increase allowed by the FERC. On our Lakehead system, we increased our rates by an average of three percent. Also on our Lakehead system, new tariffs went into effect on April 1, 2006 for an adjustment on the Terrace expansion program surcharge due to lower than expected volumes moving on the Lakehead system, and new facilities in service, that were not operating during 2005. These tariff increases, along with the four percent increase in average hauls from 692 miles in 2005 compared with 722 in 2006 resulted in a combined increase in operating revenue of approximately $35.4 million.

        Continuing volume growth related to our Mid-Continent storage terminal system in Cushing, Oklahoma, and El Dorado, Kansas, has resulted in an increase in operating revenue of approximately $6.8 million compared with 2005. Net capacity additions in 2006 bring the total storage capacity to 97 tanks and approximately 12.8 million barrels. This additional storage capacity is expected to provide ongoing fixed, variable, and spot storage revenue.

        Operating and administrative expenses for 2006 were $141.3 million, or $2.9 million less than in 2005, primarily as a result of decreased oil measurement losses which are partially offset by increased workforce related costs and materials, supplies, and other general costs.

        Workforce related costs increased due to the additional resources and related benefit costs we are charged for the operational, administrative, regulatory and compliance support necessary for our growing systems as discussed above in the year end analysis for December 31, 2007.

        Materials, supplies and other expenses coupled with repair and maintenance costs were higher in 2006 compared with 2005 due to higher pipeline inspection costs associated with our pipeline integrity management programs, increased outside contractor services, field inventory adjustments and other general costs.

        During the fourth quarter of 2005, we identified certain operating conditions on connected third-party systems that were contributing to higher levels of physical oil losses on our Lakehead system. Improvements to our oil measurement processes have resulted in fewer physical losses during 2006 on our Lakehead and Mid-Continent systems. We expect these improvements to have a continuing positive impact on our oil measurement losses going forward.

        Power costs increased $32.8 million in 2006, compared with 2005, primarily due to the increase in volumes transported on our Lakehead system and higher electricity rates we are charged by our power suppliers. We have experienced a trend of increasing electricity rates from our power suppliers due to higher natural gas and other fuel costs.

        We completed a depreciation study of the Lakehead system in the first quarter of 2006 that resulted in extending the composite remaining service life of the system assets from 21.5 to 26 years. The impact of the depreciation study was an $11.0 million reduction of depreciation expense for the full year of 2006.

Future Prospects for Liquids

        Historically, Western Canada has been a key source of oil supply serving U.S. energy needs. Canada's oil sands, one of the largest oil reserves in the world, are becoming an increasingly prominent source of supply. Combined conventional and oil sands established reserves of approximately 179 billion barrels compare with Saudi Arabia's proved reserves of approximately 264 billion barrels. The National Energy Board of Canada, or NEB, estimates that total 2007 Western Canadian Sedimentary Basin, or WCSB, production averaged approximately 2.4 million Bpd compared with 2.3 million Bpd in 2006. According to production forecasts by CAPP, Western Canadian crude oil production is projected to grow progressively from approximately 2.4 million Bpd in 2007 to 5.2 million Bpd by 2020. Conventional crude oil production is expected to decline from approximately 1.0 million Bpd to approximately 670,000 Bpd over the same period. The net increased production is expected to result from an estimated $110 billion CAD of active or

58


planned projects that are being developed in the oil sands. The projected growth in western Canadian crude production will require construction of new pipelines to ensure new oil supplies can be transported to markets in the United States.

        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.

Partnership Projects

    Southern Access

        In conjunction with Enbridge, we continue to progress on schedule with construction of the 400,000 Bpd Southern Access expansion project. We are undertaking the United States portion of the expansion on our Lakehead system. The first stage of construction will add approximately 190,000 Bpd of capacity and is on schedule for completion by the end of the first quarter of 2008. This stage of the project includes a new pipeline between Superior and Delavan, Wisconsin, along with pump station enhancements upstream and downstream of this segment.

        The second stage of the expansion project will provide additional upstream pumping capacity and a new pipeline from Delavan to Flanagan, Illinois, with completion expected by the end of the first quarter of 2009. Completion of the total Southern Access expansion project will create a 454-mile pipeline with approximately 400,000 Bpd of incremental capacity on our Lakehead system.

        As a result of the escalation of costs we have experienced with the first stage of the project for labor, materials and rights-of-way, we have revised our estimated cost to complete the project. We anticipate the ultimate cost to complete our portion of this project will approximate $2.1 billion. The impact on the project rate of return resulting from the escalation of costs is largely mitigated by the cost of service tolling arrangement used for this project. Approximately 88 percent of the cost overage will be included in the rate base, which forms the basis for determining our tariff rates for transportation. The remaining 12 percent of the project cost relates to installing larger pipe than required under current agreements which we are financing in anticipation of future expansion opportunities.

    Alberta Clipper

        The Alberta Clipper project involves construction of a new 36-inch diameter, 1,000 mile heavy crude oil pipeline from Hardisty, Alberta to Superior, generally within or adjacent to our and Enbridge's existing rights-of-way. We will construct approximately 330 miles of the new pipeline from the International Border near Neche, North Dakota to Superior and, at the request of our customers, we have revised the scope to also include a delivery connection at Clearbrook, Minnesota and an additional tank at Superior. Alberta Clipper will have an initial capacity of 450,000 Bpd and allows for expansions up to 800,000 Bpd by adding pump stations. In addition, complementary capacity on the Southern Access 42-inch pipeline from Superior to Flanagan will be obtained by installing additional pump stations. We anticipate that our share of the construction cost for the United States segment of the project will approximate $1.0 billion, in 2007 dollars, excluding capitalized interest. Alberta Clipper will be a common carrier line fully integrated with the Enbridge/Lakehead mainline systems for tolling purposes.

        In May 2007, Enbridge filed an application with the NEB, for the construction and operation of the Canadian segment of the project. In June 2007, Enbridge filed supplements to this application setting forth the tolling principles for the Canadian portion of the project, which are supported by CAPP. Hearings for the Canadian section of the project began in November 2007. Regulatory and permit applications are in progress at state and federal levels. We plan to file a set of toll principles with the FERC similar to those filed by Enbridge with the NEB for the Canadian segment of the project. The project remains subject to regulatory approvals and receipt of various permits in Canada and the United States. Enbridge is

59


progressing with land access, engineering and initial procurement commitments to facilitate commencement of project construction. Alberta Clipper is expected to be in service in mid-2010.

    North Dakota

        We substantially completed our expansion of the North Dakota system during the fourth quarter of 2007. The expansion added approximately 30,000 Bpd of mainline throughput capacity and expanded the system's feeder segment by approximately 30,000 Bpd at an approximate cost of $78.2 million. The expansion is supported by increasing crude oil production from the Bakken formation in the Williston Basin region of Montana and North Dakota.

        Regional producers in the Williston basin areas of Montana and North Dakota have expressed interest in further expansion of pipeline capacity on our North Dakota system. We have proposed an approximate $0.15 billion additional expansion that will consist of upgrades to existing pump stations, additional tankage, as well as extensive use of drag reducing agents ("DRA") that are injected into the pipeline. This second expansion of our North Dakota system is expected to increase system capacity to 161,000 Bpd from the 110,000 Bpd that is currently available. The commercial structure for this expansion is a cost-of-service based surcharge that will be added to the existing tariff rates. The proposed surcharge is similar to the structure being used on the recently completed expansion project and is subject to approval from the FERC.

    Superior and Griffith Storage

        Due to forecasted production increases of synthetic heavy crude oil that we anticipate will be transported on the Enbridge/Lakehead mainline systems from Western Canada to Chicago, we are constructing additional crude oil storage tanks at Superior and Griffith to accommodate the anticipated volumes. We completed construction and placed into service one tank with approximately 330,000 barrels of operational capacity at Superior in August 2007 and another tank at Griffith with approximately 330,000 barrels of operational capacity in December 2007. We are also building two tanks with operational capacity of approximately 205,000 barrels each that are scheduled to be completed during 2008.

    Mid-Continent Terminal Storage

        We continue to experience strong interest from customers in securing access to long-term contract storage capacity at our Cushing, Oklahoma terminal. During 2006, we obtained commitments and initiated construction of an additional 5.0 million barrels of storage tanks, 1.1 million barrels of which were completed in late December 2006. During 2007, we completed construction of additional storage tanks with approximately 3.9 million barrels of capacity. Our total Mid-Continent terminal capacity is approximately 16.7 million barrels, which includes 1.4 million barrels of operational storage.

Enbridge and Other Projects

    Spearhead Pipeline

        In another effort to provide shippers access to new markets, Enbridge acquired a pipeline that runs from Cushing to Chicago, Illinois. The reversed pipeline, renamed Spearhead, began delivering Canadian crude oil to the major oil hub at Cushing in March 2006 and has operated at or near its capacity of 125,000 Bpd. In the first half of 2007, Enbridge successfully concluded a binding open season for expansion of the pipeline to 190,000 Bpd, with binding commitments for capacity of 30,000 Bpd. In December 2007, the FERC issued a favorable declaratory order effectively approving the tolling methodology and priority service for shippers with binding commitments. The Spearhead pipeline is complementary to our Lakehead system as Western Canadian crude oil is carried on our Lakehead system as far as Chicago, and then transferred to the Spearhead pipeline. The Spearhead pipeline expansion is expected to be in service in early 2009.

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    Southern Access Extension

        In July 2006, Enbridge announced that it received support from shippers and CAPP for its 36-inch diameter Southern Access Extension pipeline from Flanagan, Illinois to Patoka, Illinois. The extension will broaden the reach of the Enbridge/Lakehead mainline system to incremental markets accessible from the Patoka hub. The project is scheduled for completion in the first quarter of 2009. This project is being undertaken by Enbridge, however, we will benefit from the incremental volumes moving through our Lakehead system to reach this extension. Enbridge filed a petition for declaratory order with the FERC in October 2007, which is currently pending approval.

    Southern Lights

        Following completion of a successful open season in 2006, Enbridge initiated its Southern Lights project to construct a diluent pipeline from Chicago, Illinois to Edmonton, Alberta, Canada to meet the growing demand for crude oil diluent required to transport the heavy oil and bitumen (a thick, tar-like form of oil) being produced in increasing volumes from the Alberta oil sands. The project involves the exchange of a 156-mile section of pipeline we own for a similar section of a new pipeline to be constructed as part of the project. In addition, this project involves a reconfiguration of our light crude mainline system which will provide an additional 45,000 Bpd of effective capacity at no cost to us. We expect to benefit from increased heavy crude oil shipments, which will be facilitated by the diluent line.

        Enbridge has filed applications with the NEB for approval of all facets of the Canadian portion of the project and the majority of necessary applications for the United States portion of the project with United States federal and state regulatory agencies. Enbridge filed a petition for declaratory order with the FERC setting forth the rate structure for establishing tolls and the proposed swap of line 13 discussed above, which the FERC approved in late December 2007. In conjunction with our Southern Access project, the Southern Lights project has been allowed the right to exercise eminent domain for right-of-way in Illinois. Early construction and right-of-way acquisition related to this project continues in tandem with stage one of the Southern Access project. This project is expected to be placed in service in 2010.

    Texas Access Pipeline

        Non-binding expressions of interests received in June 2007 demonstrated strong shipper support for the construction of a new heavy crude oil pipeline system to transport crude oil from Patoka, Illinois to the U.S. Gulf Coast. Enbridge (U.S.) Inc. and ExxonMobil Pipeline Company are jointly pursuing development of the Texas Access Pipeline, which as proposed will provide approximately 445,000 Bpd of new capacity from Patoka, Illinois to Texas Gulf Coast refineries with a projected in-service date of mid-2011. The proposed project comprises a new 768-mile, 30-inch diameter pipeline that begins in the vicinity of Mobil Pipe Line Company's Patoka, Illinois crude oil terminal southward to Nederland, Texas, coupled with an 88-mile, 24-inch lateral to transport crude oil onward from Nederland to a delivery point in Houston, Texas. The new pipeline will allow for connectivity to existing terminals in both Nederland and Houston, and will be constructed in the same corridor with existing pipelines owned by ExxonMobil Pipeline Company. The initial capacity of the Patoka-to-Nederland segment of the pipeline would be 445,000 Bpd, and the initial capacity of the Nederland-to-Houston segment would be 169,000 Bpd.

        In December 2007, an open season was announced to solicit binding 15-year shipper commitments for the proposed Texas Access Pipeline, which ends on March 14, 2008. Construction of this project would complement our Lakehead system and further support its expansion.

    Eastern PADD II Access

        Enbridge has held discussions with several refiners in the eastern United States to gauge interest in supporting the development of a pipeline to provide incremental pipeline capacity to this market. Development of this project is ongoing and is expected to provide up to approximately 100,000 Bpd of heavy Canadian crude oil to the Eastern PADD II market by late 2010. Additional access initiative

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discussions have commenced with other area refiners to provide incremental infrastructure in this area for service in the 2013 timeframe. Construction of both of these projects would be complementary to our Lakehead system.

Other Matters

        In September 2007, the Alberta Royalty Review Panel issued its recommendations to the government of the Province of Alberta calling for the adoption of measures to increase the Alberta government's share of revenues from oil sands development. A majority of the recommendations of the report were subsequently adopted by the Alberta government and will become effective January 1, 2009. These measures may impact how oil sands developers evaluate future projects and this may reduce the level of future volumes we expect to flow through the Enbridge/Lakehead mainline system.

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:

        The following tables set forth the operating results of our Natural Gas segment assets and average daily volumes of our major systems in MMBtu/d for the periods presented:

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
 
   (dollars in millions)

  
Operating revenues   $ 3,444.0   $ 3,020.7   $ 2,352.1  
   
 
 
 
Cost of natural gas     2,990.0     2,601.1     2,018.7  
Operating and administrative     266.7     215.4     175.0  
Depreciation and amortization     96.1     70.3     66.0  
Gain on sale of assets     —     —     (18.1 )
   
 
 
 
Expenses     3,352.8     2,886.8     2,241.6  
   
 
 
 
Operating income   $ 91.2   $ 133.9   $ 110.5  
   
 
 
 
East Texas(2)     1,180,000     1,019,000     860,000  
Anadarko     591,000     582,000     488,000  
North Texas     348,000     294,000     265,000  
UTOS     192,000     181,000     158,000  
Midla     115,000     109,000     106,000  
AlaTenn     44,000     41,000     59,000  
Bamagas     119,000     88,000     29,000  
Other Major Intrastates(3)     236,000     223,000     230,000  
   
 
 
 
Total     2,825,000     2,537,000     2,195,000  
   
 
 
 
(1)
In November 2007, we sold the KPC system which contributed average daily volumes of approximately 23,000, 29,000 and 31,000 for the years ended December 31, 2007, 2006 and 2005.

(2)
In December 2005, we sold the South Texas assets and a sour gas system in East Texas which had a combined average daily volume of approximately 55,000 MMBtu/d, of this amount 33,000 MMbtu/d relates to South Texas.

(3)
We have included in other major intrastates the volumes of our Gloria system for the years ended December 31, 2007, 2006, and 2005 of 62,000, 65,000, and 44,000.

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        We recognize revenue upon delivery of natural gas and NGLs to customers, when services are rendered, pricing is determinable and collectibility is reasonably assured. We derive revenue in our Natural Gas segment from the following types of arrangements:

Fee-Based 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 provided and do not depend directly on commodity prices. Revenues of the Natural Gas segment that are derived from transmission services consist of reservation fees charged for transmission of natural gas on the FERC-regulated interstate natural gas transmission pipeline systems, while revenues from intrastate pipelines are generally derived from the bundled sales of natural gas and transmission services.

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 and by the use of derivative financial instruments to hedge open positions. We will continue to hedge a significant amount of our commodity price risk to support the stability of our cash flows. Refer to Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk and Note 14 of our consolidated financial statements beginning on page F-1 of this report for more information about the derivative activities we use to mitigate this commodity price risk.

        These other types of arrangements are categorized as follows:

        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. In order to protect our cash flows from volatility that can result from fluctuations in commodity prices, we enter into derivative financial instruments to effectively fix the sales price of the natural gas and NGLs we anticipate receiving under the terms of these contracts. We target approximately 70 to 80 percent hedge coverage of our anticipated near-term exposure to commodity prices using derivative financial instruments. As a result of entering into these derivative financial instruments, we have largely fixed the amount of cash that we will receive in the

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future when we sell the processed natural gas and NGLs, although the market price of these commodities will continue to fluctuate during that time.

Year ended December 31, 2007 compared with year ended December 31, 2006

        Our Natural Gas segment produced $91.2 million of operating income for the year ended December 31, 2007, a decrease of $42.7 million from the $133.9 million of operating income generated during the prior year. Operating income in 2007 included unrealized, non-cash mark-to-market net losses from our derivative activities totaling $59.0 million which are $58.9 million more than the $0.1 million of net losses we recorded in the same period of 2006. Also contributing to operating income were volume increases, improved pricing for our services and greater processing margins, which represent revenues less the cost of natural gas purchased for processing. Partially offsetting these increases in operating income were higher operating costs and depreciation.

        The operating income of our Natural Gas segment for the year ended December 31, 2007 was negatively affected by unrealized non-cash, mark-to-market net losses of $59.0 million from our derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133. These losses were predominantly the result of hedges placed on the optional processing we perform on our three major systems which do not qualify for hedge accounting. In 2006, our operating income was reduced by unrealized non-cash, mark-to-market net losses of $0.1 million, including $1.9 million of losses that resulted from ineffectiveness of our cash flow hedges and $1.8 million of gains derived from our derivative financial instruments that did not qualify for hedge accounting treatment under SFAS No. 133. Refer also to Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk and Note 14 of our consolidated financial statements beginning on page F-1 of this report for more information about our derivative activities.

        Average daily volumes on our major natural gas systems increased 11 percent, or approximately 288,000 MMBtu/d, for the year ended December 31, 2007, compared with the corresponding period of 2006. The increased volumes for 2007 continue to reflect our ongoing investments to further expand the capacity of our systems and services. We completed the following projects during 2007 and 2006 which have contributed to the increases in average daily volumes and operating results of our major natural gas systems:

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        During 2007, we have added approximately 195 MMcf/d of additional processing capacity to our Natural Gas systems, which has served to increase our processing margin. During 2007, NGL prices continued to trend higher relative to natural gas prices, providing a favorable environment for the production of NGLs from our processing assets, similar to the pricing environment experienced during 2006. A variable element of our Natural Gas segment's operating income is derived from the processing of natural gas under keep-whole arrangements that exist within our East Texas, North Texas and Anadarko systems. Operating income derived from our keep-whole processing increased to approximately $108.8 million for the year ended December 31, 2007 from $79.2 million for the same period in 2006 primarily due to the current favorable pricing environment and increased volumes processed associated with these types of arrangements and increased processing plant capacity. Partially offsetting our favorable processing results were operational issues associated with our Zybach processing plant that occurred during the first quarter of 2007 which reduced processing margins by approximately $10.5 million. We completed the necessary repairs and modifications during April 2007 and the plant has since been operating as expected throughout the remainder of 2007.

        Natural gas measurement losses occur as part of the normal operating conditions associated with our natural gas pipelines. The quantification and resolution of measurement losses is complicated by several factors including varying qualities of natural gas in the streams gathered and processed through our systems, changes in weather temperatures and variances in measurement that are inherent in metering technologies. During the first quarter 2007, we identified operating conditions on our gathering systems which contributed to an increase in measurement losses. We have since installed separator equipment to identify and eliminate free-water in the natural gas streams, one of the underlying causes for the increase in measurement losses during 2007. For the year ended December 31, 2007, we estimate that measurement losses resulted in approximately $21.3 million of additional cost to our natural gas systems relative to the same period of 2006.

        A portion of our Natural Gas segment is exposed to risks from fluctuations in commodity prices associated with the percentage of proceeds, percentage of liquids, and percentage of index contracts that we negotiate with producers. Under the terms of these contracts, we retain a portion of the natural gas and NGLs we process in exchange for providing these producers with our services. In order to protect our

65


unitholders from the volatility in cash flows that can result from fluctuations in commodity prices, we enter into derivative financial instruments to fix the sales price of the natural gas and NGLs we anticipate receiving under the terms of these contracts. We target approximately 70 to 80 percent hedge coverage of our anticipated near-term exposure to commodity prices using derivative financial instruments. As a result of entering into these derivative financial instruments, we have largely fixed the amount of cash that we will pay for natural gas and receive in the future when we sell the processed natural gas and NGLs, although the market price of these commodities will continue to fluctuate during that time. Another significant portion of the revenue we receive is derived from fees charged for gathering and treating of natural gas volumes and other related services which are not directly dependent on commodity prices.

        Operating and administrative costs associated with our Natural Gas segment were $51.3 million, or 24 percent, greater for 2007 than 2006, primarily as a result of increased workforce related cost associated with the expansion of our systems, maintenance activities and other costs that are mostly variable with volumes. Our workforce related costs increased for the year ended December 31, 2007 over the same period in 2006 due to the additional resources and related benefit costs we are charged for the operational, administrative, regulatory and compliance support necessary for our existing assets and the expansion of our natural gas operations. In addition, our general partner charges us the costs associated with employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative services. The portion of compensation and related costs we are charged is dependent upon such items as estimated time spent, miles of pipe and headcount. In addition we have experienced an increase in outside contract labor cost, given the high demand and competitive rates within our industry as a result of continuous pipeline expansions across the areas we serve.

        Our materials and supplies coupled with repair and maintenance costs increased for the year ended December 31, 2007 over the same period in 2006, predominantly due to the increase in volumes and expansion of our natural gas systems. Materials, supplies and other costs include chemicals used in our processing activities, materials purchased for repair and maintenance purposes, utility costs to run our plants, pumps and other similar costs that are mostly variable with volumes. Repair and maintenance costs include compressor maintenance, downtime for routine and unscheduled maintenance, pipeline integrity costs and other similar items that have increased with the expansion of our existing natural gas systems. An example of these increasing costs is methanol, a chemical used on our systems which cost $2.06 per gallon in 2006. At the end of 2007, this chemical had risen in cost to $2.49 per gallon. Welders, inspectors and other skilled laborers and technicians hourly labor costs have increased in cost by amounts well in excess of the rate of overall inflation as measured by the CPI or PPI inflation index. We expect our operating and administrative costs will continue to increase in future periods as greater volumes of natural gas flow through our systems and we continue to expand our natural gas operations.

        Our depreciation and amortization expense for the year ended December 31, 2007 increased by approximately $25.8 million over the same period in 2006, primarily as a result of capital projects completed and placed in-service during late 2006 and throughout 2007. We expect our depreciation expense to continue to increase as we complete capital projects related to our continued expansion of our natural gas operations.

Year ended December 31, 2006 compared with year ended December 31, 2005

        Our Natural Gas segment contributed $133.9 million of operating income in 2006, an increase of $23.4 million from the $110.5 million it contributed in 2005. The increase in operating income is primarily attributable to favorable commodity prices which contributed to higher revenue generated by our processing assets in excess of the cost we incur for the natural gas used in processing. Additionally, operating income was higher due to volume increases on each of our three largest systems resulting from additional wellhead supply contracts and the expansion of our transportation and processing capacity. Partially offsetting the benefit provided by favorable volumes and commodity prices are expenses we recorded in 2006 of approximately $8.3 million for NGL purchases and transportation and fractionation

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charges that relate to prior years we had not previously recorded. Our 2006 volumes and operating results are exclusive of the volumes and operating results associated with our December 2005 sale of the South Texas assets and a sour gas system located on our East Texas system.

        Average daily volumes on our major natural gas systems were up approximately 13 percent in 2006, compared with 2005. Increases in our volumes for 2006 are attributable to our ongoing investments to expand the capacity of our systems and services. Our investments in the following projects that were completed during 2006 contributed to the increase in the average daily volumes and operating results on our major natural gas systems:

        In addition to the investments we have made to expand our volumes in the areas served by our natural gas assets, the volume and revenue growth is also the result of additional wellhead supply contracts and robust drilling activity in the Anadarko basin, Bossier Trend and Barnett Shale.

        Throughout a majority of 2006, we have experienced a favorable pricing environment with regard to our assets and our processing. During 2006, NGL and crude oil prices remained high relative to natural gas prices which have declined from the high prices reached in late 2005. This increase includes the contribution to operating income derived from our keep-whole processing, of $79.2 million, including $19.1 million from our North Texas system, for the year ended December 31, 2006, in excess of the $29.0 million generated in 2005 under this contract structure. Due to the volatility associated with commodity prices, the revenue less cost of natural gas we derive from our processing activities in future periods could be adversely affected if the pricing environment becomes unfavorable, which can occur if the prices for NGLs substantially decline and the price of natural gas significantly increases. We attempt to hedge a majority of our mandatory processing to minimize the effects volatility in commodity prices can have on our processing activities.

        Operating income of our Natural Gas segment for the year ended December 31, 2006 includes unrealized non-cash, mark-to-market net losses of $0.1 million, including $1.9 million of losses resulting from ineffectiveness of our cash flow hedges and $1.8 million of gains derived from our derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133. In 2005, our operating income was reduced by $8.1 million of unrealized, non-cash, mark-to-market net losses that we incurred, primarily from derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133. The decline in our unrealized derivative fair value losses in 2006 is largely due to a decline in the current and forward prices of natural gas and NGLs during 2006 from the high levels reached in 2005 due to hurricanes Rita and Katrina that caused supply disruptions in the Gulf of Mexico resulting in a volatile pricing environment. Additionally, our unrealized derivative fair value losses in 2006 are lower due to our settlement in December 2005 for $16.3 million of natural gas collars on 2,000 MMBtu/d of natural gas through 2011 that did not qualify for hedge accounting treatment under SFAS No. 133. The settlement of these natural gas collars reduces the quantity of derivatives outstanding that do not qualify for hedge accounting treatment in our Natural Gas segment, effectively reducing the unrealized

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mark-to-market adjustments resulting from these derivatives in periods following settlement. Refer to Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk and Note 14 of our consolidated financial statements beginning on page F-1 of this report for more information about our derivative activities.

        Operating and administrative costs of our Natural Gas segment were $215.4 million, or 23 percent, greater for 2006 than 2005, primarily as a result of increased workforce related costs, maintenance activities and other costs that are mostly variable with volumes. Workforce related costs have increased due to the additional resources and related benefit costs we are charged for the operational, administrative, regulatory and compliance support necessary for our existing assets and the expansion of our natural gas operations.

        The increase in our Materials, supplies and other costs along with our Repair and maintenance costs are predominantly related to the increase in volumes and expansion of our natural gas systems. Materials, supplies and other costs include chemicals used in our processing activities, materials purchased for repair and maintenance purposes, utility costs to run our plants, pumps and other similar costs that are mostly variable with volumes. These costs were partially offset by the sale of our South Texas assets and a sour gas system located on our East Texas system in December 2005, which contributed to the decrease in Materials, supplies and other costs compared with 2005. Repair and maintenance costs include compressor maintenance, downtime for routine and unscheduled maintenance, pipeline integrity costs and other similar items that have increased with the expansion of our existing natural gas systems. During 2006, we spent approximately $10.1 million, the majority of which was in the fourth quarter of 2006, on pipeline integrity work in connection with our ongoing pipeline integrity management program in order to comply with regulatory guidance and maintain our existing pipeline integrity standards. We anticipate these costs will continue to increase as we expand our systems and increase the volumes of natural gas services we provide.

        Our other operating and administrative costs include rents and leases which primarily relate to compressor rentals, property taxes and other costs. These additional operating and administrative costs tend to vary in relation to the natural gas volumes moving on our systems or in relation to the expansion of our natural gas operations. We anticipate these costs will continue to increase as the volumes on our systems increase and we expand our systems.

        Our depreciation and amortization expense for the year 2006 exceeded the amount reported for 2005 by approximately $4.3 million, primarily as a result of capital projects completed and placed in-service during 2006 and projects completed in 2005 that were only depreciated for a partial year. The increase in depreciation expense was partially offset by modest extensions of the depreciable lives of our major natural gas systems based on a third-party study commissioned by management that was completed in the third quarter of 2005. As a result of this study, revised depreciation rates for the Anadarko, North Texas and East Texas systems were implemented effective August 1, 2005. The annual composite rate, which represents the expected remaining service life of these natural gas systems, was reduced from 4.0% to 3.4%. As a result, our depreciation expense was approximately $3.5 million and $2.5 million lower for the years ended December 31, 2006 and 2005, respectively, than if these rates had not been reduced. Additionally, we revised our depreciation rates for a portion of our FERC-regulated natural gas assets effective July 1, 2006, to reflect a decrease in the remaining service life of these natural gas assets. Depreciation expense was approximately $1.3 million higher for the year ended December 31, 2006, as a result of this decrease in the expected remaining service life of these assets.

Future Prospects for Natural Gas

        Our natural gas assets are located in the Gulf Coast and Mid-continent regions of the United States, two of the premier natural gas producing areas. As a result, there are many opportunities to connect new natural gas supplies either by installing new facilities or acquiring adjacent third-party gathering

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operations. Consolidation with neighboring facilities will extract efficiencies by eliminating costs, for example, by combining redundant facilities, increasing volume, and increasing processing margins. These opportunities tend to involve modest amounts of capital with attractive rates of return.

        We continue to assess various expansion opportunities to pursue our strategy for growth. While we remain committed to making accretive acquisitions in or near areas where we have a competitive advantage, we will continue to focus our efforts primarily on development of our existing pipeline systems. We may, and have, pursued opportunities to divest any non-strategic natural gas assets as conditions warrant.

        Results of our natural gas gathering and processing business depend upon the drilling activities of natural gas producers in the areas we serve. During 2007, increased drilling in the areas where our gathering systems are located contributed to the growth of volumes on our systems. We expect the growth trend in these areas to continue in the future as evidenced by external production forecasts and the strong rig counts and permitting in the areas served by our systems.

        Producer plans for drilling in the areas served by our natural gas assets are expected to result in continued production growth on our natural gas systems. To accommodate this further growth, we initiated construction on several projects to increase our gathering, processing, transportation and treating infrastructure, as well as market access capability and have completed a number of these projects as discussed above under our analysis for 2007. The remaining projects listed below continue to progress and include:

East Texas System Expansion and Extension (Project Clarity):

Other East Texas Projects:

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North Texas System Projects:

        In order to accommodate the active development and anticipated growth occurring in the Barnett Shale play in North Texas we commenced construction of two natural gas processing plants and related upstream facilities with a combined total capacity of approximately 75 MMcf/d. During the third quarter 2007, we placed the 35 MMcf/d Weatherford processing facility in service and completed construction on a further expansion of 40 MMcf/d in the fourth quarter of 2007.

Anadarko System Projects:

        We continue to increase our field compression in the Anadarko region, which we expect will begin contributing to our operating results during the remainder of 2008.

        When fully operational, we expect that the new assets we are constructing will provide additional sources of cash flow for us. We continue to evaluate other projects that could further integrate our major Texas-centered natural gas pipeline systems.

        A number of new interstate natural gas transportation pipelines are being constructed that may alter interstate transportation of natural gas. These newly constructed pipelines could affect the operating results of certain of our existing market-based interstate and intrastate natural gas pipelines, primarily the AlaTenn, Midla, and MLGT systems. Conversely, our supply based gathering systems may benefit from enhanced capacity out of our gathering areas.

        We recently initiated negotiations with a major customer of our Enbridge Pipelines (Midla), L.L.C., or Midla, mainline transmission system for the renewal of a contract that is set to expire in August 2008. The ultimate outcome of these negotiations is uncertain. The modest amount of operating income we derive from the Midla mainline transmission system could be reduced in the event the customer terminates the contract or renews it at lower rates than we currently charge. Further, such an outcome could reduce Midla's ability to recover the carrying value of its noncurrent assets, which approximate $34 million at December 31, 2007.

        In November 2007, we sold our Kansas pipeline system, or KPC, to an unrelated party for $133 million in cash, subject to adjustments for working capital items. KPC is an interstate natural gas transmission system, which serves the Wichita, Kansas and Kansas City, Kansas markets and includes approximately 1,120 miles of pipeline ranging in diameter from 4 to 12 inches, along with three compressor stations. KPC represents a business within our Natural Gas segment that we do not consider strategic to the ongoing central operations of our core Natural Gas segment assets. The operating results of the KPC system were not material to our consolidated operating results or those of our Natural Gas segment for the years ended December 31, 2007, 2006 and 2005. We recognized a gain of $32.6 million on the sale of KPC, which is presented in income from discontinued operations.

        In December 2005, Calpine Corporation ("Calpine") and many of its subsidiaries, including the subsidiary that owns the two utility plants served by our Bamagas system, filed voluntarily petitions to restructure under Chapter 11 of the United States Bankruptcy Code. Since filing for bankruptcy, Calpine has continued to perform under the terms of its agreements with Bamagas. In June 2007, Calpine and certain of its subsidiaries filed a Joint Plan of Reorganization (the "Plan") and Disclosure Statement with the United States Bankruptcy Court. On December 19, 2007 the U.S. Bankruptcy Court for the Southern District of New York issued a decision confirming Calpine's reorganization plan. In addition, the Bamagas contracts with Calpine have been reaffirmed. Calpine announced at the end of January 2008 that it has emerged from Bankruptcy.

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

 
   Year Ended December 31,
  
 
   2007
   2006
   2005
  
 
   (dollars in millions)

  
Operating revenues   $ 3,290.5   $ 2,975.5   $ 3,706.8  
   
 
 
 
Cost of natural gas     3,256.9     2,913.5     3,744.6  
Operating and administrative     8.0     5.4     4.1  
Depreciation and amortization     1.6     0.5     0.5  
   
 
 
 
Expenses     3,266.5     2,919.4     3,749.2  
   
 
 
 
Operating income (loss)   $ 24.0   $ 56.1   $ (42.4 )
   
 
 
 

        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 end users of the natural gas. A majority of the natural gas we purchase is produced in Texas markets where we previously had limited physical access to the primary interstate pipeline delivery points, or hubs, such as the Houston Ship Channel. As a result of the completed segments of our natural gas system expansions and other initiatives during 2007, our Marketing business now has access to several interstate natural gas pipelines, which it can use to transport natural gas to primary markets where it can be sold at more favorable prices. Prior to 2007, physical pipeline constraints often limited the ability of our Marketing business to transport the natural gas to these primary markets, which would more frequently require our Marketing business to transport natural gas to alternate market points with less favorable pricing.

        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 "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 the requirements of SFAS No. 133, which can create volatility in the operating results of our Marketing segment.

        In addition to the market access provided by our 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 offset the demand charges associated with these transportation agreements, we look for market conditions that allow us to lock in the price differential or spread between the pipeline receipt point and pipeline delivery point. This allows our Marketing business to lock in a fixed sales margin inclusive of pipeline demand charges. We accomplish this by transacting basis swaps between the index where the natural gas is purchased and the index where the natural gas is sold. By transacting a basis swap between those two indices, we can effectively lock in a margin on the combined natural gas purchase and the natural gas sale, mitigating the demand charges on these transportation agreements and limiting the Partnership's exposure to cash flow volatility that could arise in markets where the transporting the natural gas becomes uneconomical. However, the structure of these transactions precludes our use of hedge accounting under the requirements of SFAS No. 133, which can create volatility in the operating results of our Marketing segment.

        In addition to natural gas 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

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injected natural gas and withdrawn natural gas, as well as storage fees, the injection and withdrawal price differential, or "spread," 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 the SFAS No. 133 guidelines. 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 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.

        Marketing 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, 2007 compared with year ended December 31, 2006

        Our Marketing business has benefited from the increased access to preferred natural gas markets resulting from our natural gas system expansions and other initiatives. Although the operating income of our Marketing segment for the year ended December 31, 2007 of $24.0 million is $32.1 million lower than the $56.1 million for the year ended December 31, 2006, the change is primarily due to the $68.3 million decrease in unrealized, non-cash mark-to-market gains associated with our derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133. For the year ended December 31, 2007, we recorded $3.8 million of unrealized mark-to-market losses from our derivative activities as compared with $64.5 million of unrealized mark-to-market gains for the year ended December 31, 2006. The unrealized, mark-to-market losses for the year ended December 31, 2007, are the result of modest increases in the forward and daily market prices of natural gas from December 31, 2006. During the year ended December 31, 2006, declines in the forward and daily market prices of natural gas from the historically high prices existing at December 31, 2005 produced significant unrealized mark-to-market gains in our portfolio of derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133. We expect the unrealized mark-to-market gains and losses associated with our portfolio of derivative financial instruments to be offset when the related physical transactions are settled. Refer to the discussions included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 14 to our Financial Statements beginning on page F-1 of this report).

        The operating results of our Marketing business for the year ended December 31, 2007 also include gains of approximately $16.3 million that we realized upon the sale of natural gas inventory, including approximately $6.9 million of gains from the settlement of derivative financial instruments hedging our natural gas inventory. Partially offsetting these gains are non-cash charges of $4.3 million that we recorded to reduce the cost basis of our natural gas inventory to fair market value, which is $12.7 million less than the $17.0 million non-cash charges we recorded during the year ended December 31, 2006. The market price for natural gas in various storage locations may experience declines during the year from the prices at which the inventory was purchased. Due to our hedging structures, we expect that a majority of these charges will be offset by future financial transactions that will settle at the time the natural gas inventory is sold.

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Year ended December 31, 2006 compared with year ended December 31, 2005

        For the year ended December 31, 2006, the operating income of our Marketing segment increased $98.5 million to $56.1 million, from a loss of $42.4 million in 2005. The significant increase in the operating income of our Marketing segment for 2006 is primarily due to unrealized, non-cash, mark-to-market net gains of approximately $64.5 million compared with unrealized mark-to-market net losses of $50.3 million for 2005. These unrealized mark-to-market changes are associated with derivative financial instruments that do not qualify for hedge accounting treatment under SFAS No. 133. The unrealized, mark-to-market gains for 2006 are the result of a decline in the forward and daily market price of natural gas from the historically high prices experienced in 2005. Additionally, the basis between the index where the natural gas is purchased and the index where the natural gas is sold has declined in correlation with the decline in the forward market price of natural gas contributing to the unrealized, mark-to-market net gains for 2006.

        The operating results of our Marketing segment for the year ended December 31, 2006, also include non-cash charges totaling $17.0 million attributable to reducing the cost basis of our natural gas inventory to fair market value. Natural gas prices as published by Platt's Gas Daily for Henry Hub were approximately $10.08 per MMBtu at December 31, 2005, which had declined to $5.64 per MMBtu at December 31, 2006. As a result of the decline in the price of natural gas from 2005 to 2006, we recorded charges totaling $17.0 million during 2006 to reduce the cost basis of our inventory to fair market value. Partially offsetting this charge are gains of approximately $3 million that we realized upon settlement of derivative financial instruments hedging our natural gas inventory for 2006. Due to our hedging structures, we expect that a majority of the lower of cost or market inventory charges will be offset by future financial and physical transactions that will settle at the time the natural gas inventory is sold.

Corporate

Year ended December 31, 2007 compared with year ended December 31, 2006

        Interest expense was $99.8 million in 2007 compared with $110.5 million in 2006. The decrease is due to $36.7 million of additional interest capitalized on our construction projects during the year compared with same period of 2006, partially offset by higher average debt balances and weighted average interest rates. Capitalized interest was approximately $47.4 million on our construction projects for 2007 compared with $10.7 million capitalized in 2006. Our weighted average interest rate was approximately 6.11% for the year ended December 31, 2007, compared with approximately 5.82% during 2006. Our debt balances are higher as a result of the capital expenditures we made to expand our pipeline systems that were partially financed by additional borrowings.

        We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Our income tax expense of $5.1 million for the year ended December 31, 2007 results from the enactment, by the state of Texas, of a new state tax computed on our 2007 modified gross margin. No comparable tax existed during the year ended December 31, 2006. We determined this tax to be an income tax under the provisions of SFAS No. 109, Accounting for Income Taxes ("SFAS No. 109"). We computed our income tax expense for the year ended December 31, 2007 by applying a 0.57% apportioned state income tax rate to taxable margin, as defined in State of Texas statutes. Our income tax expense represents a 2% effective rate as applied to pretax book income.

        In July 2007, the State of Michigan enacted substantial changes to its tax structure that become effective in 2008. The new system is comprised of two parts, a modified gross receipts tax at 1% and a 6.04% tax on income that will be levied on our Michigan operating activities. We determined that these taxes are income taxes under the provisions of SFAS No. 109. Our initial accounting for the enactment of this income tax did not materially affect our results of operation, financial position, or cash flows.

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Year ended December 31, 2006 compared with year ended December 31, 2005

        Interest expense was $110.5 million in 2006 compared with $107.7 million in 2005. The increase is the result of higher debt balances and weighted average interest rates, partially offset by approximately $10.7 million of interest capitalized on our construction projects for 2006 compared with $4.0 million capitalized in 2005. Our weighted average interest rate was approximately 5.82% for the year ended December 31, 2006, compared with approximately 5.78% during 2005. Our debt balances are higher at December 31, 2006 compared with December 31, 2005 as a result of the capital expenditures we have made to expand our existing systems to improve the service capabilities of our assets.

        Included in other income for the year ended December 31, 2006, is approximately $4.5 million that we received as settlement for an insurance claim that we filed in connection with an interruption to the operations of our Lakehead system resulting from a fire that occurred at Suncor's upgrader site in January 2005.

LIQUIDITY AND CAPITAL RESOURCES

General

        We believe that our ability to generate cash flow, in addition to our access to capital, is sufficient to meet the demands of our current and future operating and investment needs. Our primary cash requirements consist of normal operating expenses, capital expenditures for our expansion projects, enhancement and maintenance capital expenditures, debt service payments, distributions to our partners, acquisitions of new assets and businesses, and payments associated with our derivative transactions. Short-term cash requirements, such as operating expenses, maintenance capital expenditures, debt service payments and quarterly distributions to our partners, are expected to be funded by operating cash flows. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our Credit Facility. We expect to fund long-term cash requirements for enhancements, expansion projects, and acquisitions from several sources, including cash flows from operating activities, borrowings under our commercial paper program, our Credit Facility, and the issuance of additional equity and debt securities. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and credit rating at the time.

        Our current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses with less focus on acquisitions. The internal growth projects we have planned for our Natural Gas business (see Natural Gas segment—Future Prospects), coupled with the Southern Access and Alberta Clipper projects on our Lakehead system (see Liquids segment—Future Prospects), will require significant expenditures of capital over the next several years. We expect to fund these expenditures from a balanced combination of additional issuances of partnership units and long-term debt. Our planned internal growth projects will require us to bear the cost of constructing these new assets before we will begin to realize a return on them.

Capital Resources

Equity Capital

        Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private equity markets to obtain the capital necessary to fund these projects. During 2007, we obtained approximately $628.8 million of cash through equity issuances in both public and private transactions, including contributions of approximately $12.5 million from our general partner to maintain its two percent general partner interest. We used the proceeds from these offerings to repay outstanding commercial paper we had previously issued to finance a portion of our capital expansion

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projects and for use in future periods to fund additional expenditures under our capital expansion programs.

        The following table presents historical information about offerings of our limited partner interests since January 2005:

Issuance Date
   Class of
Limited
Partnership
Interest
   Number of
units
Issued
   Offering Price
per 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)
2007                                
May   Class A   5,300,000   $ 58.000   $ 301.9   $ 6.1   $ 308.0
April   Class C   5,931,086   $ 53.113     314.4     6.4     320.8
       
       
 
 
        11,231,086         $ 616.3     12.5   $ 628.8
       
       
 
 

2006
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
August   Class C   10,869,565   $ 46.000   $ 500.0   $ 10.2   $ 510.2
       
       
 
 

2005
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December   Class A   136,200   $ 46.000   $ 6.0   $ 0.2   $ 6.2
November   Class A   3,000,000   $ 46.000     132.1     2.8     134.9
February   Class A   2,506,500   $ 49.875     124.8     2.7     127.5
       
       
 
 
2005 Totals       5,642,700         $ 262.9   $ 5.7   $ 268.6
       
       
 
 
(1)
Net of underwriters' fees and discounts, commissions and issuance expenses.

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

Available Credit

        A significant source of our liquidity is provided by the commercial paper market. We have a $600 million commercial paper program that is supported by our long-term Credit Facility, which we access primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions, at rates that are generally lower than the rates available under our Credit Facility.

        In the second half of 2007, the domestic credit markets were adversely affected by a sharp increase in the credit risk associated with U.S. asset-backed securities. Due to the increase in perceived risks in the credit markets, and the need of large financial institutions to preserve capital, investors turned to investments in U.S. government securities, while selling off more risky credit securities. The lack of demand for domestic credit instruments other than U.S. government securities have, at times, limited our ability to access the commercial paper markets. However, our Credit Facility, which supports our commercial paper program, continues to provide us with adequate liquidity to fund our growth projects.

        In addition to our Credit Facility, we executed an unsecured revolving credit agreement with Enbridge U.S. Inc., a wholly-owned subsidiary of Enbridge Inc. (the "EUS Credit Agreement") in December 2007, which provides us with access to an additional $500 million of financing under substantially the same terms as our Credit Facility.

        Although the U.S. credit markets remain volatile, we were able to successfully raise approximately $593 million during the second half of 2007 through the issuance of $200 million of our senior, unsecured zero coupon notes due 2022 (the "Zero Coupon Notes") and $400 million of our fixed/floating rate, unsecured, long-term junior subordinated notes due 2067. Both of these issuances are discussed below and

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in Note 9 to our consolidated financial statements included in Item 8. Financial Statements to this report on Form 10-K.


Outstanding Indebtedness

        The following table presents the components of our outstanding indebtedness:

 
   December 31,
  
 
   2007
   2006
  
 
   (in millions)

  
Current maturities of long-term debt:              
  Current portion of First Mortgage Notes   $ 31.0   $ 31.0  
   
 
 
  Note payable to affiliate   $ —   $ 136.2  
   
 
 

Long-term debt:
 
 
 
 
 
 
 
  Commercial Paper   $ 268.5   $ 443.7  
  Credit Facility     400.0     —  
  Affiliate Credit Agreement     —     —  
  First Mortgage Notes     93.0     124.0  
  4.000% senior notes due 2009     200.0     200.0  
  7.900% senior notes due 2012(1)     100.0     100.0  
  4.750% senior notes due 2013     200.0     200.0  
  5.350% senior notes due 2014     200.0     200.0  
  5.875% senior notes due 2016     300.0     300.0  
  7.000% senior notes due 2018(1)     100.0     100.0  
  7.125% senior notes due 2028(1)     100.0     100.0  
  5.950% senior notes due 2033     200.0     200.0  
  6.300% senior notes due 2034     100.0     100.0  
  Senior, unsecured zero coupon notes due 2022     203.6     —  
  8.05% fixed/floating rate junior subordinated notes due 2067     400.0     —  
  Unamortized discount     (2.2 )   (1.6 )
   
 
 
Total long-term debt   $ 2,862.9   $ 2,066.1  
   
 
 
Note payable to affiliate(2)   $ 130.0   $ —  
   
 
 
(1)
Debt of Enbridge Energy, Limited Partnership, one of our operating subsidiaries.

(2)
Ranks subordinate to our Credit Facility and other senior indebtedness, and ranks equally with current and future Junior Notes.


Credit Facility

        Our Credit Facility, as amended, is a revolving term facility that matures in April 2012. In April 2007, we entered into the Second Amended and Restated Credit Agreement which among other things increased the maximum principal amount of credit available to us at any one time from $1 billion to $1.25 billion and allows us to request increases in the maximum principal amount of credit available at any one time from $1.25 billion to $1.5 billion. We pay interest on the amounts outstanding at variable rates equal to a "Base Rate" or a "Eurodollar Rate" as defined in the Credit Facility. In the case of Eurodollar Rate loans, an additional margin is charged which varies depending on our credit rating and the amounts drawn under the facility. We are also charged a facility fee on the entire amount of the Credit Facility, regardless of the amount drawn, which also varies depending on our credit rating. We continue to use our Credit Facility to support our commercial paper program and provide short-term financing for our operations and capital expansion programs.

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        The amounts we can borrow under the terms of our Credit Facility are reduced by the principal amount of our commercial paper issuances and the balance of our letters of credit outstanding. At December 31, 2007, we had $400 million outstanding under our Credit Facility at a weighted average interest rate of 5.22% and letters of credit totaling $159.7 million. At December 31, 2007, we could borrow $420.3 million under the terms of our Credit Facility, determined as follows:

 
    
   2007
  
 
    
   (in millions)

  
Total credit available under Credit Facility   $ 1,250.0  
Less:   Amounts outstanding under Credit Facility     (400.0 )
    Balance of letters of credit outstanding     (159.7 )
    Principal amount of commercial paper issuances     (270.0 )
       
 
Total amount we could borrow at December 31, 2007   $ 420.3  
       
 

        Our Credit Facility contains restrictive covenants that require us to maintain a maximum leverage ratio of 5.50 to 1.0 for periods ending on or before March 31, 2009; a ratio of 5.25 to 1.0 thereafter, for periods ending on or before March 31, 2010; and a ratio of 5.00 to 1.0 for periods ending June 30, 2010 and following. At December 31, 2007, our leverage ratio was approximately 3.6. 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.


Commercial Paper Program

        At December 31, 2007, we had $270 million in principal amount of commercial paper outstanding, with unamortized discount of $1.5 million, at a weighted average interest rate of 5.36%, before the effect of our interest rate hedging activities. We had net repayments of approximately $171.5 million during 2007 under our commercial paper program, which include gross issuances of $5,172.7 million and gross repayments of $5,344.2 million. At December 31, 2007, we could issue an additional $330 million in principal amount under our commercial paper program.


First Mortgage Notes

        The First Mortgage Notes are collateralized by a first mortgage on substantially all of the property, plant and equipment of Enbridge Energy, Limited Partnership, (the "OLP"), and are due and payable in equal annual installments of $31.0 million until their maturity in 2011. The Notes contain various restrictive covenants applicable to us, and restrictions on the incurrence of additional indebtedness by the OLP, including compliance with certain debt issuance tests. We were in compliance with these covenants at December 31, 2007. We believe these issuance tests will not negatively affect our ability to access the credit markets to finance future expansion projects. Under the First Mortgage Notes Agreements, we cannot make cash distributions more frequently than quarterly in an amount not to exceed Available Cash for the immediately preceding calendar quarter. If we repay the Notes prior to their stated maturities, the First Mortgage Note Agreements provide for the payment of a redemption premium by us.


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 million of senior notes issued by the OLP (the "OLP Notes"). The borrowings under our Senior Notes are non-recourse to our General Partner and Enbridge Management. All of our Senior Notes pay interest semi-annually and have varying maturities and terms as presented in the table above. Our Senior Notes do not contain any covenants restricting us from issuing

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additional indebtedness. 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, 2007.

        The OLP, our operating subsidiary that owns the Lakehead system, has $300 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 as set forth in the table above. 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 ("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, 2007.

        In August 2007, we received net proceeds of approximately $200 million from a private placement of our senior, unsecured zero coupon notes due 2022 (the "Zero Coupon Notes"), which at maturity will be payable in the aggregate principal amount of $442 million. We initially recorded the Zero Coupon Notes in long-term debt at the amount of proceeds we received from the private placement, which we refer to as the issue price. The carrying amount at December 31, 2007 includes $3.6 million associated with the accretion of interest we recognized as interest expense during the period. The Zero Coupon Notes are scheduled to mature on August 28, 2022, although they may be called by the note holders prior to the scheduled maturity date on August 28 of any year commencing on August 28, 2009, at a price equal to the then accreted value of the called Zero Coupon Notes. The Zero Coupon Notes have a yield of 5.36% on a semi-annual compound basis and rank equally in right of payment to all of our existing and future senior indebtedness, as set forth in our senior indenture. We used the net proceeds from this private placement to repay a portion of our outstanding commercial paper and Credit Facility borrowings that we had previously incurred to fund a portion of our capital expansion projects.

        In December 2006, we issued $300 million in aggregate principal amount of our 5.875% Senior Notes due 2016 in a public offering, from which we received proceeds of $297.6 million, after payment of underwriting discounts and commissions and estimated offering expenses. We used the proceeds to repay a portion of our outstanding commercial paper and to finance a portion of our capital expansion projects.


Junior Subordinated Notes

        In September 2007, we issued and sold $400 million in principal amount of our 8.05% fixed/floating rate, unsecured, long-term junior subordinated notes due 2067, which we refer to as the Junior Notes. We received net proceeds of approximately $393.0 million, after payment of underwriting discounts, commissions and offering expenses, which we used to temporarily reduce a portion of our outstanding commercial paper and Credit Facility borrowings that we incurred to finance a portion of our capital expansion projects. The Junior Notes are subordinate in right of payment to all of our existing and future senior indebtedness, as defined in the related indenture.

Indebtedness to Affiliates

Hungary Note Payable

        As of December 31, 2007 and 2006, we had $130.0 million and $136.2 million, respectively, in amounts outstanding under notes payable to Enbridge Hungary Ltd., an affiliate of our general partner, which we refer to as the Hungary Note. In December 2007, we repaid $145.0 million of the original Hungary Note, including $8.8 million of accrued interest, with proceeds we received from entering into a new Hungary Note agreement with substantially the same terms and approximately $15 million from our existing cash. The new Hungary Note bears interest at a fixed rate of 8.4% per annum that is payable semi-annually in June and December of each year through its maturity in December 2017. Similar to the old Hungary Note,

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the new note allows us the option of paying accrued and unpaid interest in the form of additional indebtedness by increasing the principal balance of the note for the amounts due. Consistent with the original Hungary Note, the new Hungary Note has cross-default provisions that are triggered by events of default under our First Mortgage Notes or defaults under our Credit Facility. The new Hungary Note is subordinate to our Credit Facility and other senior indebtedness, and ranks equally with current and future Junior Notes. We entered into the original Hungary Note agreement in connection with our acquisition of the Midcoast system in October 2002. For the year ended December 31, 2006, we converted interest payable in the amount of $4.4 million into debt by increasing the principal balance of the original Hungary Note.

EUS Credit Agreement

        In December 2007, we entered an unsecured revolving credit agreement with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge. Enbridge is the indirect owner of Enbridge Energy Company, Inc., our general partner. The EUS Credit Agreement provides for a maximum principal amount of credit available to us at any one time of $500 million for a three-year term that matures in December 2010. The EUS Credit Agreement also includes financial covenants that are consistent with those in our Second Amended and Restated Credit Agreement as discussed above. Amounts borrowed under the EUS Credit Agreement bear interest at rates that are consistent with the interest rates set forth in our Second Amended and Restated Credit Agreement. At December 31, 2007, we had no balances outstanding under the EUS Credit Agreement and the full amount remains available for our use.


Credit Ratings

        The following table reflects the ratings that have been assigned to our debt and the debt of our wholly-owned subsidiary, Enbridge Energy, Limited Partnership at December 31, 2007:

 
   Standard &
Poor's
   Moody's
   Dominion Bond
Rating Service
Enbridge Energy Partners, L.P.            
  Outlook   Stable   Negative   Stable
  Corporate   BBB   Baa2   BBB
  Commercial Paper   A-2   P-2   R-2(middle)
  Medium Term Notes & Unsecured Debentures   BBB   Baa2   BBB
  Junior subordinated debt   BB+   Baa3   BB(high)
Enbridge Energy, Limited Partnership            
  Outlook   Stable   Negative   NR
  Senior secured   BBB+   Baa1   NR
  Senior unsecured   BBB   Baa1   NR

NR—No rating is available

        Moody's continues to maintain our Baa2 rating with a negative outlook. This reflects Moody's view that our financial profile is weaker than those of our similarly rated peers. However, Moody's believes that this weaker financial profile is offset to a degree by our low business risk profile that stems from our highly regulated and/or contracted liquids and natural gas systems and our strategy of hedging a significant portion of our commodity exposure. While our substantial organic growth capital expenditure program will place our financial profile under near term pressure until these projects are commissioned and increase our reliance on the capital markets, Moody's believes that completion of our organic growth projects should contribute to a further reduction in our overall business risk profile and that the cash flow generated by these projects as they are commissioned will strengthen our financial profile. Following the successful execution of both the construction and financing of these growth projects, an improved rating outlook by Moody's is possible.

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Summary of Obligations and Commitments

        The following table summarizes the principal amount of our obligations and commitments at December 31, 2007:

Future Minimum Commitments
   2008
   2009
   2010
   2011
   2012
   Thereafter
   Total
 
   (in millions)
Long-term debt and notes payable to affiliates   $ 31.0   $ 434.6   $ 31.0   $ 31.0   $ 770.0   $ 1,730.0   $ 3,027.6
Purchase commitments(1)     305.4     —     —     —     —     —     305.4
Power commitments(2)     2.9     0.2     0.2     —     —     —     3.3
Other operating leases     11.9     8.9     2.7     0.4     —     0.1     24.0
Right-of-way(3)     1.7     1.7     1.7     1.7     1.7     41.0     49.5
Product purchase obligations(4)     55.7     38.5     34.5     32.7     31.0     84.3     276.7
Service contract obligations(5)     36.0     28.8     25.6     18.6     7.3     0.5     116.8
   
 
 
 
 
 
 
Total   $ 444.6   $ 512.7   $ 95.7   $ 84.4   $ 810.0   $ 1,855.9   $ 3,803.3
   
 
 
 
 
 
 
(1)
Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our expansion projects.

(2)
Represents commitments to purchase power in connection with our Liquids segment.

(3)
Right-of-way payments are estimated to be approximately $1.7 million per year for the remaining life of all pipeline systems, which has been assumed to be 25 years for purposes of calculating the amount of future minimum commitments beyond 2012.

(4)
We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at prices approximating market at the time of delivery.

(5)
The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.

Cash Requirements for Future Growth

Capital Spending

        We expect to make significant expenditures during the next three years for the construction of additional natural gas and crude oil transportation infrastructure. Anticipated growth in Western Canadian oil sands production and the need to reach newer markets has prompted the Southern Access, Alberta Clipper and related projects associated with our liquid systems. In 2008, we expect to spend approximately $1.4 billion on these and other projects with the expectation of realizing additional cash flows as projects are completed and placed into service. At December 31, 2007, we had approximately $305.4 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment during 2008.

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 includes the replacement of system components and equipment which is worn, obsolete or completing its useful life. 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 forecasted expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the capital necessary to accomplish our growth objectives. The following table sets forth our estimates of capital required for system enhancement and core maintenance expenditures through December 31, 2008. Although we anticipate making the

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expenditures in 2008, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions. 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. We made capital expenditures of $1,980.2 million, including $59.8 million on core maintenance activities, for the year ended December 31, 2007.

        For the full year ending December 31, 2008, we anticipate our capital expenditures to approximate the following:

 
   Total
Forecasted
Expenditures
 
   (in billions)
Other system enhancements   $ 0.5
Core maintenance activities     0.1
Southern Access expansion     0.6
Alberta Clipper     0.2
   
    $ 1.4
   

Major Construction Projects

        The following table includes our active major construction projects and additional information regarding our projected cost, actual expenditures through December 31, 2007, the incremental capacity that will or has become available upon completion of the project and the periods we expect to complete the construction. The projected amounts included in this table may change due to modifications of the scope of the project, increases in materials and construction costs and other factors that are outside of our direct control.

 
   Capital Expenditures
   Estimated Incremental Capacity
    
 
   Estimated
Total Cost
   Actual
Expenditures
Inception
through
December 31,
2007
   Storage
   Oil
   Natural
Gas
   Expected Completion
 
   (in billions)

   (KBbl)

   (Kbpd)

   (MMcf/d)

    
Southern Access expansion (Lakehead)   $ 2.1   $ 1.1   —   400   —   2009
Clarity (East Texas)     0.6     0.6   —   —   700   Early 2008
Alberta Clipper     1.2     —   —   450   —   Mid-2010
North Dakota phase 6 expansion     0.2     —   —   51   —   Early 2010
Griffith and Superior storage tanks     0.1     —   1,220   —   —   Mid-2008
   
 
 
 
 
   
  Total   $ 4.2   $ 1.7   1,220   901   700    
   
 
 
 
 
   

        Including major expansion projects and excluding acquisitions, ongoing capital expenditures are expected to be significant over the next three years due to our Southern Access expansion and Alberta Clipper projects. Core maintenance capital is also anticipated to increase over that period of time due to growth in our pipeline systems and aging of infrastructure.

        We anticipate funding the system enhancement capital expenditures temporarily through the issuance of commercial paper and borrowing under the terms of our Credit Facility, with permanent debt and equity

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funding being obtained when appropriate. Core maintenance expenditures are expected to be funded by operating cash flows.

        We expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Expenditure levels have continued to increase as pipelines age and require higher levels of inspection or maintenance; however, these are viewed to be consistent with industry trends.

        The following table presents major construction projects that we have completed during 2007 and additional information regarding the estimated cost, actual expenditures through December 31, 2007, the incremental capacity that has become available upon completion of the project and the periods construction was completed.

 
   Capital Expenditures
   Estimated Incremental Capacity
    
 
   Estimated
Total Cost
   Actual
Expenditures
Inception
through
December 31,
2007
   Storage
   Oil
   Natural
Gas
   Period Completed
 
   (in billions)

   (KBbl)

   (Kbpd)

   (MMcf/d)

    
North Dakota system expansion     0.1     0.1   —   30   —   November 2007
Cushing terminal storage tanks     0.1     0.1   4,970   —   —   Throughout 2007
Processing and treating plant expansions     0.3     0.3   —   —   1,130   Various
   
 
 
 
 
   
  Total   $ 0.5   $ 0.5   4,970   30   1,130    
   
 
 
 
 
   

Acquisitions

        We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing. The market for acquiring energy transportation assets is active and competition among prospective acquirers of assets has been significant. While we remain committed to making accretive acquisitions in or near areas where we already operate or have a competitive advantage, we will continue to focus our efforts on development of our existing pipeline systems. Additionally, we may pursue opportunities to divest of any non-strategic assets as conditions warrant.

        We expect that the funds needed to achieve growth through acquisitions will be obtained through issuances of commercial paper, borrowings under the terms of our Credit Facility, term debt and issuances of additional partnership interests.

Derivative Activities

        We use derivative financial instruments (e.g., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the volatility of our cash flows and manage the purchase and sales prices of our commodities. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability or anticipated transaction and are not entered into with the objective of speculating on commodity prices.

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        The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at December 31, 2007 for each of the indicated calendar years:

 
   Notional
   2008
   2009
   2010
   2011
   2012
  
 
   ($ in millions)

  
Swaps                                    
  Natural gas(1)   328,985,388   $ (32.9 ) $ (35.6 ) $ (32.8 ) $ (30.8 ) $ (5.9 )
  NGL(2)   10,163,878     (98.9 )   (43.6 )   (13.8 )   (4.3 )   —  
  Crude(2)   1,411,221     (17.7 )   (7.2 )   (4.4 )   (3.4 )   (1.9 )
Options—calls                                    
  Natural gas(1)   1,461,000     (1.3 )   (1.5 )   (1.4 )   (1.4 )   —  
Options—puts                                    
  Natural gas(1)   1,401,000     —     —     —     —     —  
  NGL(2)   763,403     0.1     0.6     —     —     —  
       
 
 
 
 
 
  Totals       $ (150.7 ) $ (87.3 ) $ (52.4 ) $ (39.9 ) $ (7.8 )
       
 
 
 
 
 
(1)
Notional amounts for natural gas are recorded in millions of British thermal units ("MMBtu").

(2)
Notional amounts for NGL and Crude are recorded in Barrels ("Bbl").

Operating Activities

        Net cash provided by our operating activities was $463.4 million in 2007 compared with $321.6 million in 2006. The improved operating cash flow is primarily attributable to sales of inventory during 2007 that we did not make in 2006 and other changes in working capital accounts related to general timing differences between the collection on and payment of our current and related party accounts.

Investing Activities

        Net cash used in our investing activities during the year ended December 31, 2007 was $1,765 million, an increase of $898 million from the $867 million used during the same period of 2006. The increase is primarily attributable to the $1,062.6 million increase in our investments in property, plant and equipment during the year ended December 31, 2007, over the amount spent during the year ended December 31, 2006, partially offset by $133 million of proceeds we received from the sale of our KPC system. The increase in our capital expenditures during the year ended December 31, 2007 is directly attributable to our previously described expansion projects. We expect that cash flows used in our investing activities will remain at high levels throughout the periods we are performing extensive expansions to our Lakehead and East Texas systems.

Financing Activities

        Net cash provided by financing activities during the year ended December 31, 2007 was $1,167.5 million, an increase of $527.3 million from the $640.2 million generated during the year ended December 31, 2006. We increased the level of our financing activities during 2007 to obtain permanent financing for our capital expansion projects. The permanent financing we completed during the year ended December 31, 2007 includes the following:

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        Also contributing to the increase in our financing activities for the year ended December 31, 2007 are net Credit facility borrowings of $400.0 million, which include gross borrowings of $740.0 million and gross repayments of $340.0 million. We also had net repayments of commercial paper of $171.5 million, which include gross issuances of $5,172.7 million and gross repayments of $5,344.2 million.

        During the year ended December 31, 2007, cash distributions to our partners increased to $245.4 million from $227.4 million in the same period of 2006 due to:

Cash Distributions

        We make quarterly distributions to our General Partner and the holders of our limited partner units in an amount equal to our "available cash." As defined in our partnership agreement, "available cash" represents for any calendar quarter, the sum of all of our cash receipts plus net reductions to reserves less all of our cash disbursements and net changes to reserves. We retain reserves to provide for the proper conduct of our business, to stabilize distributions to our unitholders and the General Partner and, as necessary, to comply with the terms of any of our agreements or obligations. Enbridge Management, as the delegate of the General Partner under a delegation of control agreement, computes the amount of our available cash.

        As the owner of our i-units, Enbridge Management does not receive distributions in cash. Instead, each time that we make a cash distribution to the General Partner and the holders of our Class A and Class B common units, the number of i-units owned by Enbridge Management and the percentage of total units in us owned by Enbridge Management increases automatically under the provisions of our partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the sum of Enbridge Management's shares that are then outstanding. The amount of this increase in i-units is determined by dividing the cash amount distributed per limited partner unit by the average price of one of Enbridge Management's listed shares on the NYSE for the 10-trading day period immediately preceding the ex-dividend date for Enbridge Management's shares multiplied by the number of shares outstanding on the record date. The cash equivalent amount of the additional i-units is treated as if it had actually been distributed for purposes of determining the distributions to be made to the General Partner.

        Until August 15, 2009, in lieu of cash distributions, the holders of our Class C units will receive quarterly distributions of additional Class C units with a value equal to the quarterly cash distributions we pay to the holders of our Class A and Class B common units, which we collectively refer to as common units. The number of additional Class C units we will issue is determined by dividing the quarterly cash distribution per unit we pay on our common units by the average market price of a Class A common unit as

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listed on the New York Stock Exchange for the 10-trading day period immediately preceding the ex-dividend date for our Class A common units multiplied by the number of Class C units outstanding on the record date. As a result, the number of Class C units and the percentage of our total units owned by holders of the Class C units will increase automatically under the provisions of our partnership agreement. The cash equivalent amount of the additional Class C units is treated as if it had actually been distributed for purposes of determining the distributions to be made to the General Partner.

        After August 15, 2009, the holders of our Class C units will receive quarterly cash distributions equal to those paid to the holders of our common units. Subject to the approval of holders of our outstanding units in accordance with the then-existing requirements of the principal national securities exchange on which the Class A common units are listed, the Class C units will convert into Class A common units on a one-for-one basis. If our unitholders do not approve the conversion, the holders of our Class C units will receive quarterly cash distributions equal to 115 percent of those paid to the holders of our common units. Prior to conversion, holders of our Class C units will not be entitled to receive any quarterly cash distribution until the holders of our common units have received a minimum quarterly cash distribution of $0.59 per common unit. As of May 2007, the NYSE no longer requires unitholder approval to convert the Class C units to Class A common units.

        For purposes of calculating the sum of all distributions of available cash, the cash equivalent amount of the additional i-units and Class C units that are issued when a distribution of cash is made to the General Partner and owners of common units is treated as distribution of available cash, even though the i-unit holder and holders of our Class C units will not receive cash. We retain the cash for use in our operations to finance a portion of our capital expansion projects. During 2007, we distributed a total of 889,938 i-units through quarterly distributions to Enbridge Management, compared with 969,200 in 2006. Additionally, we distributed a total of 1,072,423 Class C units to the holders of our Class C units. We retained $107.5 million in 2007 related to the i-unit and Class C unit distributions, compared with $54.7 million in 2006.

        Our current annual cash distribution rate is $3.80 per unit, or $0.950 per quarter compared with $3.725 for the year ended December 31, 2007. We expect that all cash distributions will be paid out of operating cash flows over the long term; however, from time to time, we may temporarily borrow under our Credit Facility or issue additional commercial paper for the purpose of paying cash distributions until we realize the full impact of assets being developed on operations.

Off-Balance Sheet Arrangements

        We have no significant off-balance sheet arrangements.

Subsequent Events

    Distribution to Partners

        On January 28, 2008, the board of directors of Enbridge Management declared a distribution payable to our partners on February 14, 2008. The distribution was paid to unitholders of record as of February 6, 2008, of our available cash of $96.7 million at December 31, 2007, or $0.950 per limited partner unit. Of this distribution, $66.0 million was paid in cash, $12.9 million was distributed in i-units to our i-unitholder, $17.2 million was distributed in Class C units to the holders of our Class C units and $0.6 million was retained from the General Partner in respect of the i-unit and Class C unit distributions to maintain its two percent general partner interest.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

        Our selection and application of accounting policies is an important process that has developed as our business activities have evolved and as new accounting pronouncements have been issued. Accounting

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decisions generally involve an interpretation of existing accounting principles and the use of judgment in applying those principles to the specific circumstances existing in our business. We make every effort to comply with all applicable accounting principles and believe the proper implementation and consistent application of these principles is critical. However, not all situations we encounter are specifically addressed in the accounting literature. In such cases, we must use our best judgment to implement accounting policies that clearly and accurately present the substance of these situations. We accomplish this by analyzing similar situations and the accounting guidance governing them and consulting with experts about the appropriate interpretation and application of the accounting literature to these situations.

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

        We believe our critical accounting policies and estimates discussed in the following paragraphs address the more significant judgments and estimates we use in the preparation of our consolidated financial statements. Each of these areas involves complex situations and a high degree of judgment either in the application and interpretation of existing accounting literature or in the development of estimates that affect our consolidated financial statements. Our management has discussed the development and selection of the critical accounting policies and estimates related to the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent liabilities with the Audit, Finance & Risk Committee of Enbridge Management's board of directors.

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

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

Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment

        We capitalize expenditures related to property, plant and equipment, subject to a minimum rule, that have a useful life greater than one year for (1) assets purchased or constructed; (2) existing assets that are replaced, improved, or the useful lives have been extended; or (3) all land, regardless of cost. Acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs are expensed as incurred.

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        During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt, and, in our regulated businesses that apply the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, or SFAS No. 71, an equity return component.

        We categorize our capital expenditures as either core maintenance or enhancement expenditures. Core maintenance expenditures are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment that are worn, obsolete or near the end of their useful lives. Examples of core maintenance expenditures include valve automation programs, cathodic protection, zero-hour compression overhauls and electrical switchgear replacement programs. Enhancement expenditures improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues, and enable us to respond to governmental regulations and developing industry standards. Examples of enhancement expenditures include costs associated with installation of seals, liners and other equipment to reduce the risk of environmental contamination from crude oil storage tanks, costs of sleeving a major segment of the pipeline system following an integrity tool run, natural gas or crude oil well-connects, natural gas plants and pipeline construction and expansion.

        Regulatory guidance issued by the FERC requires us to expense certain costs associated with implementing the pipeline integrity management requirements of the U.S. Department of Transportation's Office of Pipeline Safety. Under this guidance, beginning in January 2006, costs to 1) prepare a plan to implement the program, 2) identify high consequence areas, 3) develop and maintain a record keeping system and 4) inspect, test and report on the condition of affected pipeline segments to determine the need for repairs or replacements, are required to be expensed. We adopted this guidance prospectively in January 2006 for all our pipeline systems. Costs of modifying pipelines to permit in-line inspections, certain costs associated with developing or enhancing computer software and costs associated with remedial mitigation actions to correct an identified condition continue to be capitalized. We have historically capitalized initial in-line inspection programs, crack detection tool runs and hydrostatic testing costs conducted for the purposes of detecting manufacturing or construction defects. Beginning January 2006, costs of this nature are expensed as incurred which is consistent with industry practice and the regulatory guidance issued by the FERC. However, we continue to capitalize initial construction hydrostatic testing cost and subsequent hydrostatic testing programs conducted for the purpose of increasing pipeline capacity in accordance with our capitalization policies. Also capitalized are certain costs such as sleeving or recoating existing pipelines, unless the expenditures are incurred as a single event and not part of a major program, in which case we expense these costs as incurred. Our adoption of the regulatory guidance did not significantly affect our financial position, results of operations or cash flows.

        We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of their estimated useful lives or the estimated remaining lives of the crude oil or natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

        We record depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities. Under the group method, for all segments, upon the disposition of property, plant and equipment, the cost less net proceeds is normally charged to accumulated depreciation and no gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we will recognize a gain or loss in our consolidated statements of income for the difference between the cash received and the net book value of the assets sold. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. At regular intervals, we retain the services of independent consultants to assist us with

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assessing the reasonableness of the useful lives we have established for the property, plant and equipment of our major systems. Based on the results of these regular assessments we may make modifications to the assumptions we use to determine our depreciation rates.

        We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses and the market and business environments to identify indicators that may suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

Assessment of Recoverability of Goodwill and Intangibles

        Goodwill represents the excess of the purchase price over the fair value of net assets acquired in a business combination. Goodwill is not amortized, but is tested for impairment annually based on the carrying values as of the end of the second quarter, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. Impairment occurs when the carrying amount of a reporting unit exceeds its fair value. At the time we determine that impairment has occurred, the carrying value of the goodwill is written down to its fair value. To estimate the fair value of the reporting units, we make estimates and judgments about future cash flows, as well as revenue, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with our most recent five-year plan, which we use to manage the business.

        Preparation of forecast information for use in our five-year plan involves significant judgment. Actual results can, and often do, differ from the projections and assumptions we make in preparing these forecasts. These changes can have a negative impact on our estimates of impairment, which could result in charges to income. In addition, further changes in the economic and business environment can affect our original and ongoing assessments of potential impairment.

        Other intangible assets consist of customer contracts for the purchase and sale of natural gas, and natural gas supply opportunities, which we amortize on a straight-line basis over the weighted average useful life of the underlying assets, which is the period over which the asset is expected to contribute directly or indirectly to our future cash flows.

        We evaluate the carrying value of the intangible assets whenever certain events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability of intangibles, we compare the carrying value to the undiscounted future cash flows the intangibles are expected to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangibles, the intangibles are written down to their fair value. If there are changes to any of our estimates and assumptions, actual results may differ.

Asset Retirement Obligations

        We record a liability for the fair value of our asset retirement obligations, or ARO, on a discounted basis, in the period in which the liability is incurred. Typically we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an

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ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for asset retirement obligations when assets are taken out of service or otherwise abandoned.

        The provisions of Financial Accounting Standards Board ("FASB") Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 ("FIN 47") require us to recognize a liability and related asset, consistent with SFAS No. 143, for the fair value of conditional asset retirement obligations that we can reasonably estimate. FIN 47 also provides specific guidance regarding when an asset retirement obligation is reasonably estimable including when sufficient information is available to apply an expected present value technique. Our implementation of FIN 47 did not have a material impact effect on our consolidated financial statements.

        We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for a minority of our onshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate an abandonment retirement obligation cost. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's intent, or the asset's estimated economic life. Useful lives of most pipeline systems are primarily derived from available supply resources and the ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the ARO. Indeterminate ARO costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.

Derivative Financial Instruments

        Our net income and cash flows are subject to volatility stemming from changes in interest rates and commodity prices of natural gas, NGLs, condensate and fractionation margins (the relative price differential between NGL sales and the offsetting natural gas purchases). To reduce the volatility of our cash flows, we use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the purchase and sales prices of the commodities and fix the interest rate on our variable rate debt.

        The accounting treatment for our derivative financial instruments is determined by the guidance of SFAS No. 133 and is dependent on each instrument's intended use, how it is designated and the extent to which the derivative financial instrument is effective in reducing the risk that it is intended to hedge. To qualify for hedge accounting, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

        Derivative financial instruments qualifying for hedge accounting treatment that we use can generally be divided into two categories: 1) cash flow hedges, or 2) fair value hedges. We enter into cash flow hedges to reduce the variability in cash flows related to forecasted transactions. We enter into fair value hedges to reduce the risk of changes in the value of a recognized asset or liability. Cash flow and fair value hedges are considered highly effective if they are able to substantially offset (i.e., more than 80 percent) the changes in cash flow or fair value of the risk that is being hedged. The extent to which a derivative financial instrument designated as a hedge does not offset the changes in cash flow or fair value of the risk being hedged is considered ineffective. At inception and on an ongoing basis we assess whether the derivative

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financial instruments we use in our hedging transactions are highly effective in offsetting changes in cash flows or fair values of the hedged items.

        All of our derivative financial instruments are recorded in our consolidated financial statements at fair market value as current and long-term assets or liabilities on a net basis by counterparty and are adjusted each period for changes in the fair market value. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay or receive to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We use external market quotes and indices to value substantially all of the financial instruments we utilize.

        Derivative financial instruments that we designate and qualify as cash flow or fair value hedges under the requirements of SFAS No. 133, receive hedge accounting treatment for the effective portion of the derivative financial instrument. Under hedge accounting, any unrealized gain or loss in fair market value of the effective portion of a derivative financial instrument designated as a cash flow hedge is recorded as an asset or liability with an offset deferred in Accumulated other comprehensive income ("AOCI"), a component of partners' capital, until the underlying hedged transaction occurs. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges of forecasted commodity purchases and sales are included in cost of natural gas and cash flow hedges of forecasted interest payments are included in Interest expense on our consolidated statements of income in the period the hedged transaction occurs. Under hedge accounting, the realized and unrealized gain or loss in the fair market value of a derivative financial instrument designated as a fair value hedge is recorded as an asset or a liability with the offset recorded in our consolidated statements of income as a component of Cost of natural gas for fair value hedges of our commodities and as a component of interest expense for fair value hedges of our indebtedness both of which are offset by the changes in the fair market value of the underlying hedged item.

        Under the guidance of SFAS No. 133, the changes in fair market value, both realized and unrealized gains and losses, of derivative financial instruments that 1) do not qualify for hedge accounting, 2) are not designated as hedges and 3) are ineffective, are recognized each period in our consolidated statements of income. These changes in fair market value are recognized as a component of cost of natural gas for our commodity derivative financial instruments and as a component of interest expense for derivative financial instruments of our interest rates. We refer to the accounting treatment for derivative financial instruments that do not qualify for hedge accounting as mark-to-market accounting. Our preference, whenever possible, is for our derivative financial instruments to receive hedge accounting treatment to mitigate the non cash earnings volatility that arises under mark-to-market accounting treatment.

        Our cash flow is only affected to the extent the actual derivative contract is settled by 1) making or receiving a payment to/from the counterparty; or 2) by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, a derivative contract is settled when the physical transaction that underlies the derivative financial instrument occurs.

        Gains and losses that we have deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued, remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter.

        One of the primary factors that can affect our operating results each period is the price assumptions we use to value our derivative financial instruments. To the extent that these derivative financial instruments are ineffective or do not qualify for hedge accounting treatment under the requirements of SFAS No. 133, they are accounted for using the mark-to-market method of accounting and any change in the fair market value is reflected in our consolidated statements of income as a component of cost of natural gas or interest expense, depending on whether the derivative financial instrument relates to a commodity or interest rate. We use published market price information where available, or quotations from OTC market makers to find executable bids and offers. The valuations also reflect the potential

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impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, modeling risk, credit risk of our counterparties and operational risk. The amounts we report in our consolidated financial statements change quarterly as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

Commitments, Contingencies and Environmental Liabilities

        We accrue reserves for contingent liabilities, including environmental remediation and clean-up costs, when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Estimates of the liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors, and include estimates of associated legal costs. These estimates also consider prior experience remediating contaminated sites, other companies' clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances and any revisions are reflected in our earnings in the period in which they are reasonably determinable. We evaluate recoveries from insurance coverage separately from our liability and, when recovery is reasonably assured, we record and report an asset separately from the associated liability in our financial statements. New environmental developments, such as increasingly strict environmental laws and regulations and new claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial cost and future liabilities.

        We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Both internal and external legal counsel evaluate our potential exposure to adverse outcomes. When a range of probable loss can be estimated, we accrue the most likely amount, or at least the minimum of the range of probable loss. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to review our estimates, income may be affected.

Crude Oil Over/Short Balance and Crude Oil Measurement Gains/Losses

        Crude oil over/short balance and crude oil measurement gains/losses are inherent in the transportation of crude oil due to evaporation, measurement differences and blending of commodities in transit in addition to other factors. We estimate our crude oil measurement gains/losses and our crude oil over/short balance based on mathematical calculations and physical measurements, which include assumptions about the type of crude oil, its market value, normal physical losses due to evaporation and capacity limitations of the system. A material change in these assumptions may result in a change to the carrying value of our crude oil over/short balance or revision of our crude oil measurement gain/loss estimates. We include the crude oil measurement gains/losses in our operating and administrative expenses on our consolidated statements of income and the crude oil over/short balance in accounts payable and other in the consolidated statements of financial position if the balance is a liability and in inventory if the balance is in an asset position.

Operational Balancing Agreements and Natural Gas Imbalances

        We record payables and receivables associated with our natural gas pipeline operational balancing agreements and natural gas imbalances monthly when a customer delivers more or less natural gas into our pipelines than they remove. These balances are either settled on a cash basis or are carried by the pipelines and shippers on an in-kind basis. We primarily estimate the value of the imbalances at month-end spot prices based on published third-party indices for the locations where the imbalances are derived using the best available third party and internal volume information. If there is a change to these estimates and assumptions, actual results may differ.

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RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Fair Value Option for Financial Assets and Liabilities

        In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Liabilities. This statement provides companies with an option to report certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to reduce the volatility in earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The provisions of SFAS No. 159 are effective at the beginning of our first fiscal year that begins after November 15, 2007, as we have elected not to early adopt the provisions of SFAS No. 159. We do not expect our adoption of SFAS No. 159 to have a material effect on our consolidated financial statements.

Fair Value Measurements

        In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurement. The statement is effective for fiscal years beginning after November 15, 2007, and with limited exceptions is to be applied prospectively as of the beginning of the fiscal year initially adopted. We do not expect our adoption of this pronouncement to materially affect our financial statements. However, adoption of this pronouncement may affect our disclosures regarding derivative financial instruments and indebtedness.

Business Combinations

        In December 2007, the Financial Accounting Standards Board issued Statement No. 141(R), Business Combinations, which we refer to as SFAS No. 141(R). The new standard retains the fundamental requirements in FASB Statement No. 141, Business Combinations, that the acquisition method of accounting (previously referred to as the purchase method), be used for all business combinations and for an acquirer to be identified for each business combination. Among other items, SFAS No. 141(R) requires the following:

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        SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and early adoption is not permitted. Among other things, the provisions of this statement will require us to expense certain costs associated with acquisitions that were previously permitted to be capitalized which may affect our operating results in periods that we complete an acquisition.

Noncontrolling Interests

        In December 2007, the Financial Accounting Standards Board issued FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51, to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for deconsolidation of a subsidiary. Among other provisions, SFAS No. 160 requires the following:

        SFAS No. 160 is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008, and early adoption is prohibited. SFAS No. 160 requires prospective adoption as of the beginning of the fiscal year in which the provisions are initially applied, except for the presentation and disclosure requirements which shall be applied retrospectively for all periods presented. Our adoption of this standard will not have a material effect on our financial position or results of operations.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

INTEREST RATE RISK

        We utilize both fixed and variable interest rate debt, and are exposed to market risk resulting from the variable interest rates on our Credit Facility and the frequent changes in interest rates when we re-issue maturing commercial paper. To the extent that we frequently issue and re-issue commercial paper at short-term interest rates and have amounts drawn under our credit facilities at floating rates of interest, our earnings and cash flows are exposed to changes in interest rates. This exposure is managed through periodically refinancing commercial paper and floating-rate bank debt with long-term fixed rate debt and through the use of interest rate derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics. We do not have any material exposure to movements in foreign exchange rates as virtually all of our revenues and expenses are denominated in U.S. dollars. To the extent that a material foreign exchange exposure arises, we intend to hedge such exposure using derivative financial instruments.

        The following table presents the principal cash flows and related weighted average interest rates by expected maturity dates along with the carrying values and fair values of our third-party debt obligations as of December 31, 2007 and 2006.

 
   December 31, 2007
    
    
 
    
    
    
    
    
    
    
    
    
   December 31, 2006
 
    
   Expected Maturity of Carrying Amounts by Fiscal Year
    
 
   Average
Interest
Rate
   Fair
Value
   Carrying
Amount
   Fair
Value
 
   2008
   2009
   2010
   2011
   2012
   Thereafter
   Total
 
   (dollars in millions)
Liabilities                                                                
Fixed Rate:                                                                
First Mortgage Notes   9.150 % $ 31.0   $ 31.0   $ 31.0   $ 31.0   $ —   $ —   $ 124.0   $ 135.1   $ 155.0   $ 169.5
Senior notes due 2009   4.000 %   —     200.0     —     —     —     —     200.0     198.5     200.0     194.2
Senior, unsecured zero coupon notes due 2022   5.358 %   —     203.6     —     —     —     —     203.6     210.7     —     —
Senior notes due 2012   7.900 %   —     —     —     —     99.9     —     99.9     110.2     99.9     110.5
Senior notes due 2013   4.750 %   —     —     —     —     —     199.8     199.8     192.0     199.8     188.6
Senior notes due 2014   5.350 %   —     —     —     —     —     199.9     199.9     194.3     199.9     193.0
Senior notes due 2016   5.875 %   —     —     —     —     —     299.7     299.7     293.7     299.7     297.4
Senior notes due 2018   7.000 %   —     —     —     —     —     99.9     99.9     105.3     99.8     107.9
Senior notes due 2028   7.125 %   —     —     —     —     —     99.8     99.8     104.3     99.8     108.9
Senior notes due 2033   5.950 %   —     —     —     —     —     199.7     199.7     176.9     199.7     186.2
Senior notes due 2034   6.300 %   —     —     —     —     —     99.8     99.8     92.1     99.8     97.1
Junior subordinated notes due 2067   8.050 %   —     —     —     —     —     399.3     399.3     385.9     —     —

Variable Rate:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Commercial paper   5.360 %   —     —     —     —     268.5     —     268.5     268.5     443.7     443.7
  Credit Facility   5.220 %   —     —     —     —     400.0     —     400.0     400.0     —     —

        Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations. Our interest rate risk exposure does not exist within any of our segments, but exists at the corporate level where our variable rate debt obligations are issued. To mitigate the volatility of our cash flows, we use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in interest rates. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates.

        The table below provides information about our derivative financial instruments that we use to hedge the interest payments on our variable rate debt obligations which are sensitive to changes in interest rates and to lock in the interest rate on anticipated issuances of debt in the future. For interest rate swaps, the table presents notional amounts, the rates charged on the underlying notional and weighted average interest rates paid by expected maturity dates. Notional amounts are used to calculate the contractual

94

payments to be exchanged under the contract. Weighted average variable rates are based on implied forward rates in the yield curve at December 31, 2007.

 
   December 31, 2007
    
    
    
  
 
   Expected Fiscal Year of Maturity of Notional Amounts
    
    
    
  
 
   December 31, 2006
  
 
   Notional
Amount
    
    
    
    
    
    
    
    
  
 
   2008
   2009
   2010
   2011
   2012
   Thereafter
   Fair Value
   Notional Amount
   Fair Value
  
 
    
    
    
    
    
    
    
   Asset
   Liability
    
   Asset
   Liability
  
 
   (dollars in millions)

  
Interest Rate Derivatives                                                                          
Interest Rate Swaps:                                                                          
  Floating to Fixed   $ 325.0   $ (1.5 ) $ (1.4 ) $ (0.5 ) $ —   $ 0.3   $ 0.1   $ —   $ (3.0 ) $ 525.0   $ 4.3   $ —  
    Average Pay Rate     4.41 %   4.51 %   4.39 %   4.35 %   4.35 %   4.35 %   4.35 %   —     —     4.41 %            
    Average Receive Rate           LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   —     —     LIBOR              
  Fixed to Floating   $ 125.0   $ 1.0   $ 1.7   $ 0.9   $ 0.4   $ 0.1   $ —   $ 4.1   $ —   $ 125.0   $ —   $ (1.3 )
    Average Pay Rate     LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   LIBOR-
0.21
%		   —     —     LIBOR-
0.21
%		            
    Average Receive Rate     4.75 %   4.75 %   4.75 %   4.75 %   4.75 %   4.75 %   4.75 %   —     —     4.75 %            
Treasury Locks:                                                                          
  Floating to Fixed   $ 200.0   $ (8.3 ) $ —   $ —   $ —   $ —   $ —   $ —   $ (8.3 ) $ 200.0   $ 2.8   $ —  
    Average Pay Rate     4.04 %   4.04 %   —     —     —     —     —     —     —     4.68 %            
    Average Receive Rate     10YR-UST     10YR-UST     —     —     —     —     —     —     —     30YR-UST              
Interest Rate Collars:                                                                          
  Calls   $ 100.0   $ —   $ —   $ —   $ —   $ —   $ —   $ —   $ —   $ 100.0   $ 0.1   $ —  
    Average Pay Rate     5.50 %   5.50 %   5.50 %   —     —     —     —     —     —     5.50 %            
    Average Receive Rate     LIBOR     LIBOR     LIBOR     —     —     —     —     —     —     LIBOR              
  Puts   $ 100.0   $ —   $ —   $ —   $ —   $ —   $ —   $ —   $ —   $ 100.0   $ —   $ —  
    Average Pay Rate     4.17 %   4.17 %   4.17 %   —     —     —     —     —     —     4.17 %            
    Average Receive Rate     LIBOR     LIBOR     LIBOR     —     —     —     —     —     —     —              
(1)
LIBOR refers to the three-month U.S. London Interbank Offered Rate.

(2)
UST refers to United States Treasury notes.

        Our treasury locks and a portion of our interest rate collars maturing in 2008 qualify for hedge accounting treatment pursuant to the requirements of SFAS No. 133 and have been designated as cash flow hedges of future interest payments on the first $200 million of an anticipated debt issuance and interest payments on $50 million of our variable rate indebtedness, respectively. As such, the fair value of these derivative financial instruments is recorded as assets or liabilities on our consolidated statements of financial position with the changes in fair value recorded as corresponding increases or decreases in AOCI. Our floating to fixed rate interest rate swaps and a portion of our interest rate collars maturing in 2008 and 2009 hedging $250 million of our variable rate indebtedness did not qualify for hedge accounting treatment as set forth in SFAS No. 133 at December 31, 2007. As such, changes in the fair value of these derivative financial instruments are recorded in earnings as an increase or decrease in interest expense. A portion of these transactions have subsequently been re-designated as cash flow hedges of forecast floating rate indebtedness.

        The floating to fixed rate and fixed to floating rate interest rate swaps maturing in 2013 have not been designated as cash flow or fair value hedges under SFAS No. 133 and, as a result, changes in the fair value of these derivative financial instruments are recorded in earnings as an increase or decrease in interest expense.

COMMODITY PRICE RISK

        Our net income and cash flows are subject to volatility stemming from changes in commodity prices of natural gas, NGLs, condensate and fractionation margins (the relative price differential between NGL sales and the offsetting natural gas purchases). Our exposure to commodity price risk exists within our Natural Gas and Marketing segments. To mitigate the volatility of our cash flows, 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. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an

95


underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

        The following tables provide information about our derivative financial instruments at December 31, 2007 and December 31, 2006, with respect to our commodity price risk management activities for natural gas and NGLs, including condensate:

 
   At December 31, 2007
   At December 31, 2006
  
 
    
    
   Wtd Avg Price(2)
   Fair Value(3)
   Fair Value(3)
  
 
   Commodity
   Notional(1)
   Receive
   Pay
   Asset
   Liability
   Asset
   Liability
  
Contracts maturing in 2008                                              
Swaps                                              
  Receive variable/pay fixed   Natural gas   38,223,919   $ 7.19   $ 7.37   $ 7.6   $ (14.5 ) $ 9.5   $ (5.1 )
  Receive fixed/pay variable   Natural gas   33,193,191     6.57     7.48     10.3     (39.8 )   3.6     (44.1 )
    NGL   5,776,578     42.37     59.87     —     (98.9 )   2.5     (7.7 )
    Crude oil   439,721     52.04     93.17     —     (17.7 )   —     (7.0 )
  Receive variable/pay variable   Natural gas   99,960,535     7.32     7.28     7.0     (3.5 )   2.5     (0.4 )
Options                                              
  Calls (written)   Natural gas   366,000     4.31     7.80     —     (1.3 )   —     (1.3 )
  Puts purchased   Natural gas   306,000     7.91     3.40     —     —     —     —  
    NGL   398,403     64.00     44.88     0.1     —     —     —  

Contracts maturing in 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Swaps                                              
  Receive variable/pay fixed   Natural gas   11,813,065     7.94     7.59     5.5     (1.6 )   2.9     (2.1 )
  Receive fixed/pay variable   Natural gas   14,966,095     5.54     8.41     1.2     (41.8 )   0.7     (31.5 )
    NGL   3,204,335     44.22     58.66     —     (43.6 )   1.4     (1.4 )
    Crude oil   264,625     59.09     87.96     —     (7.2 )   —     (1.9 )
  Receive variable/pay variable   Natural gas   67,100,864     8.32     8.30     2.9     (1.8 )   1.4     (0.6 )
Options                                              
  Calls (written)   Natural gas   365,000     4.31     8.51     —     (1.5 )   —     (1.2 )
  Puts   Natural gas   365,000     8.51     3.40     —     —     —     —  
    NGL   365,000     58.59     42.09     0.6     —     —     —  

Contracts maturing in 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Swaps                                              
  Receive variable/pay fixed   Natural gas   2,413,505     8.24     6.23     4.4     —     2.5     (0.3 )
  Receive fixed/pay variable   Natural gas   9,670,000     4.19     8.51     —     (38.0 )   0.2     (26.1 )
    NGL   866,875     35.69     53.23     —     (13.8 )   —     (1.5 )
    Crude oil   259,150     66.83     85.73     —     (4.4 )   —     (0.6 )
  Receive variable/pay variable   Natural gas   35,935,000     8.53     8.5     1.5     (0.7 )   0.8     (0.1 )
Options                                              
  Calls (written)   Natural gas   365,000     4.31     8.58     —     (1.4 )   —     (1.0 )
  Puts   Natural gas   365,000     8.58     3.40     —     —     —     —  

Contracts maturing in 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Swaps                                              
  Receive variable/pay fixed   Natural gas   817,005     8.46     4.00     3.2     —     2.0     —  
  Receive fixed/pay variable   Natural gas   7,952,500     3.63     8.54     —     (34.1 )   —     (21.5 )
    NGL   316,090     36.02     51.86     —     (4.3 )   —     (0.6 )
    Crude oil   228,125     68.36     85.40     —     (3.4 )   —     (0.2 )
  Receive variable/pay variable   Natural gas   4,185,000     7.99     7.95     0.1     —     —     —  
Options                                              
  Calls (written)   Natural gas   365,000     4.31     8.55     —     (1.4 )   —     (0.9 )
  Puts   Natural gas   365,000     8.55     3.40     —     —     —     —  

Contracts maturing in 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Swaps                                              
  Receive variable/pay fixed   Natural gas   209,709     8.90     4.10     0.9     —     0.6     —  
  Receive fixed/pay variable   Natural gas   1,456,000     3.57     9.04     —     (6.8 )   —     (4.5 )
    Crude oil   219,600     74.85     85.39     —     (1.9 )   —     —  
  Receive variable/pay variable   Natural gas   1,089,000     7.96     7.92     —     —     —     —  
(1)
Volumes of Natural gas are measured in MMBtu, whereas volumes of NGL and Crude are measured in Bbl.

(2)
Weighted average prices received and paid are in $/MMBtu for Natural gas and in $/Bbl for NGL and Crude.

(3)
The fair value is determined based on quoted market prices at December 31, 2007 and December 31, 2006, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars.

96

Accounting Treatment

        All derivative financial instruments are recorded in the consolidated financial statements at fair market value and are adjusted each period for changes in the fair market value ("mark-to-market"). The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay or receive, other than in a forced or liquidation sale, to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We use actively traded external market quotes and indices to value substantially all of the financial instruments we utilize.

        Under the guidance of SFAS No. 133, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is adjusted to its fair market value, or marked-to-market, each period with the increases and decreases in fair value recorded in our consolidated statements of income as increases and decreases in cost of natural gas for our commodity-based derivatives and Interest expense for our interest rate derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

        If a derivative financial instrument qualifies and is designated as a cash flow hedge, a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in Accumulated other comprehensive income ("AOCI"), a component of Partners' Capital, until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in Cost of natural gas for commodity hedges and Interest expense for interest rate hedges in the period the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges, for which hedge accounting has been discontinued, remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible, to mitigate the non-cash earnings volatility that arises under from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting as set forth in SFAS No. 133, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

        If a derivative financial instrument is designated and qualifies as a fair value hedge of the change in fair market value of an underlying asset or liability, the gain or loss resulting from the change in fair market value of the derivative financial instrument is recorded in earnings adjusted by the gain or loss resulting from the change in fair market value of the underlying asset or liability. Any ineffective portion of a fair value hedge's change in fair market value will be recorded in earnings as the amount that is not offset by the gain or loss on the change in fair market value of the underlying asset or liability. We include the gains and losses associated with derivative financial instruments designated and qualifying as fair value hedges of our debt obligations in interest expense on our consolidated statements of income. Similar to derivative financial instruments designated as cash flow hedges, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

97

Non-Qualified Hedges

        Many of our derivative financial instruments qualify for hedge accounting treatment under the specific requirements of SFAS No. 133. However, we have four primary transaction types associated with our commodity derivative financial instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting under SFAS No. 133 and are referred to as "non-qualified." These non-qualified derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in cost of natural gas in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and when the associated financial instrument contract settlement is made.

        The four primary transaction types that do not qualify for hedge accounting are as follows:

98

        In each of the instances described above, the underlying physical purchase, storage and sale of natural gas and NGLs are accounted for on a historical cost or market basis rather than on the mark-to-market basis we utilize for the derivative financial instruments employed to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at historical cost) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

        We routinely enter into interest rate swaps to fix the interest rates associated with our variable rate debt, including commercial paper and bank borrowings. In August 2007, we entered into forward-starting interest rate swaps that we designated as cash flow hedges of variable rate debt to begin in October 2007 and November 2007. The specific floating rate borrowings did not take place as initially forecast, thereby causing the interest rates swaps to no longer qualify as cash flow hedges. As a result, we recorded a charge to interest expense of $1.4 million, representing the fair market value of the interest rate swaps at December 31, 2007. A portion of these transactions have subsequently been re-designated as cash flow hedges of forecast floating rate indebtedness.

Discontinuance of Hedge Accounting

        In 2005, we discontinued application of hedge accounting in connection with some of our derivative financial instruments designated as hedges of forecasted sales and purchases of natural gas. We discontinued application of hedge accounting when we determined it was no longer probable that the originally forecasted purchases and sales of natural gas would occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. As discussed above, this can occur because we have the flexibility to make changes to the underlying delivery locations for our transportation assets and to the underlying injection or withdrawal schedule for our storage assets, given changes in market conditions. One of the key criteria to achieve hedge accounting under SFAS No. 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, in 2005, we recognized previously deferred unrealized losses in our Marketing segment of approximately $9.0 million from the discontinuance of hedge accounting. In doing so, we reclassified the $9.0 million to cost of natural gas on our consolidated statements of income from AOCI. Going forward, the derivative financial instruments for which hedge accounting has been discontinued are considered to be non-qualified under SFAS No. 133, and must be marked-to-market each period, with the increases and decreases in fair value recorded as increases and decreases in earnings. Also included in the loss from discontinuance are approximately $2.1 million of net mark-to-market losses that relate to hedge positions that were closed out in 2005.

99

        The following table presents the unrealized gains and losses associated with changes in the fair value of our derivatives, which are recorded as an element of cost of natural gas and interest expense in our consolidated statements of income and disclosed as a reconciling item on our consolidated statements of cash flows:

Derivative fair value gains (losses)
   December 31,
2007
   December 31,
2006
   December 31,
2005
  
 
   (in millions)

  
Natural Gas segment                    
  Hedge ineffectiveness   $ —   $ (1.9 ) $ (2.5 )
  Non-qualified hedges     (59.0 )   1.8     (5.6 )
Marketing                    
  Non-qualified hedges     (3.8 )   64.5     (41.3 )
  Discontinued hedges     —     —     (9.0 )
   
 
 
 
    Commodity derivative fair value gains (losses)     (62.8 )   64.4     (58.4 )
Corporate                    
  Non-qualified interest rate hedges     (1.4 )   —     —  
   
 
 
 
Derivative fair value gains (losses)   $ (64.2 ) $ 64.4   $ (58.4 )
   
 
 
 

De-designation and Settlement of Derivatives

        In connection with the sale of assets in December 2005, as discussed in Note 3 to the consolidated financial statements beginning on page F-1 of this report, we settled for cash of approximately $16.3 million, natural gas collars representing derivative financial instruments on sales of 2,000 MMBtu/d of natural gas through 2011. We had previously recorded unrealized losses associated with the natural gas collars that were realized upon settlement. Additionally, we de-designated derivative financial instruments that qualified for and were designated as cash flow hedges of forecasted sales of 273 Bpd of NGLs through 2007 and contemporaneously closed out the position by entering into an offsetting derivative financial instrument, at market, on forecasted purchases of 273 Bpd of NGLs through 2007.

Derivative Positions

        Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:

 
   December 31, 2007
   December 31, 2006
  
 
   (in millions)

  
Receivables, trade and other   $ 6.5   $ 7.2  
Other assets, net     6.4     11.0  
Accounts payable and other     (165.5 )   (57.2 )
Other long-term liabilities     (192.9 )   (136.4 )
   
 
 
    $ (345.5 ) $ (175.4 )
   
 
 

        The increase in our obligation associated with derivative activities is primarily due to the increase in current and forward natural gas and NGL prices from December 31, 2006 to December 31, 2007. Our portfolio of derivative financial instruments is largely comprised of long-term fixed price natural gas sales and purchase agreements.

        We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. We regularly

100


enter into treasury locks to hedge the interest on anticipated issuances of indebtedness. The settlement of a treasury lock can result in the retention of unrecognized gains or losses in AOCI that are amortized to interest expense over the life of the related debt issuance. In connection with our 2007 issuance and sale of $400 million in principal amount of our Junior Notes, we paid $0.9 million to settle treasury locks we entered to hedge the first five years of interest payments on a portion of this obligation. The $0.9 million is being amortized from AOCI to interest expense over the five year period for which the derivative instrument was established to hedge of interest payments on the junior notes. In December 2006, we paid $10.2 million to settle treasury locks we entered to hedge a portion of the interest payments associated with our issuance of $300 million in principal amount of our senior notes. The $10.2 million is being amortized from AOCI to interest expense over the 10-year life of the senior notes.

        Also included in AOCI are unrecognized losses of approximately $2.0 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted commodity transactions that were subsequently de-designated. These unrealized losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. For the years ended December 31, 2007, 2006 and 2005, we reclassified unrealized losses of $94.8 million, $78.3 million and $33.8 million, respectively, from AOCI to cost of natural gas on our consolidated statements of income for the fair value of derivative financial instruments that were settled. We estimate that approximately $113 million of AOCI representing unrealized net losses on cash flow hedging activities at December 31, 2007, will be reclassified to earnings during the next twelve months.

        We do not require collateral or other security from the counterparties to our derivative financial instruments, all of which were rated "BBB+" or better by the major credit rating agencies.


Item 8. Financial Statements and Supplementary Data

        Our consolidated financial statements, together with the notes thereto and the independent registered public accounting firm's report thereon, and unaudited supplementary information, appear beginning on page F-2 of this report, and are incorporated by reference. Reference should be made to the "Index to Financial Statements, Supplementary Information and Financial Statement Schedules" on page F-1 of this report.


Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.


Item 9A. Controls and Procedures

DISCLOSURE CONTROLS AND PROCEDURES

        We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required in our annual and quarterly reports under the Securities Exchange Act of 1934. Our management has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2007. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective to accomplish their purpose. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.

101

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management's Annual Report on Internal Control Over Financial Reporting

        Management of Enbridge Energy Partners, L.P. and its consolidated subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f).

        The Partnership's internal control over financial reporting is a process designed under the supervision and with the participation of our principal executive and principal financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Partnership's financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles.

        The Partnership's internal control over financial reporting includes policies and procedures that:


        The Partnership's internal control over financial reporting may not prevent or detect all misstatements because of its inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or deterioration in the degree of compliance with our policies and procedures.

        Management assessed the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2007, based on the framework established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2007.

        PricewaterhouseCoopers LLP, an independent registered public accounting firm, has issued an attestation report on our internal control over financial reporting as of December 31, 2007, beginning on page F-2.

Changes in Internal Control Over Financial Reporting

        No changes in our internal control over financial reporting were made during the three months ended December 31, 2007, that would materially affect our internal control over financial reporting.


Item 9B. Other Information

        None.

102


PART III

Item 10.    Directors, Executive Officers and Corporate Governance

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

        The Partnership is a limited partnership and has no officers or directors of its own. Set forth below is certain information concerning the directors and executive officers of the General Partner and of Enbridge Management as the delegate of the General Partner under a Delegation of Control Agreement among the Partnership, the General Partner and Enbridge Management. All directors of the General Partner are elected annually and may be removed by Enbridge Pipelines, as the sole stockholder of the General Partner. All directors of Enbridge Management were elected and may be removed by the General Partner, as the sole holder of Enbridge Management's voting shares. All officers of the General Partner and Enbridge Management serve at the discretion of the respective boards of directors of the General Partner and Enbridge Management. All directors and officers of the General Partner hold identical positions in Enbridge Management.

Name
   Age
   Position
Directors and Executive Officers:        
M.O. Hesse   65   Director and Chairman of the Board
J.A. Connelly   61   Director
G.K. Petty   66   Director
D.A. Westbrook   55   Director
S.J.J. Letwin   52   Managing Director and Director
T.L. McGill   53   President and Director
S.J. Wuori   50   Executive Vice President—Liquids Pipelines and Director
Officers:        
R.L. Adams   43   Vice President—U.S. Engineering and Project Execution, Liquids Pipelines
E.C. Kaitson   51   Vice President—Law and Deputy General Counsel
D.V. Krenz   56   Vice President
J.A. Loiacono   45   Vice President—Commercial Activities
M.A. Maki   43   Vice President—Finance
A. Monaco   48   Executive Vice President—Major Projects
S.J. Neyland   40   Controller
K.C. Puckett   46   Vice President—Engineering and Operations, Gathering and Processing
J.N. Rose   40   Treasurer
A.M. Schneider   49   Vice President—Regulated Engineering and Operations, Gathering and Processing
B.A. Stevenson   52   Corporate Secretary
L.A. Zupan   52   Vice President—Liquids Pipelines Operations

        M.O. Hesse was elected as Chairman of the Board in May 2007 and as a director of the General Partner and Enbridge Management in March 2003 and serves as a member of the Audit, Finance & Risk Committee. Ms. Hesse was President and Chief Executive Officer of Hesse Gas Company from 1990 through 2003. She served as Chairman of the U.S. Federal Energy Regulatory Commission from 1986 to 1989. Ms. Hesse also served as Senior Vice President, First Chicago Corporation and Assistant Secretary for Management and Administration, U.S. Department of Energy. She is a private investor and currently serves as a director of Amec plc, Mutual Trust Financial Group, and Terra Industries, Inc.

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        J.A. Connelly was elected a director of the General Partner and Enbridge Management in January 2003 and serves as the Chairman of the Audit, Finance & Risk Committee. Mr. Connelly served as Executive Vice President, Senior Vice President and Vice President of the Coastal Corporation from 1988 to 2001. Mr. Connelly is a business consultant providing executive management consulting services.

        G.K. Petty was elected a director of the General Partner in February 2001 and Enbridge Management upon its formation and serves on the Audit, Finance & Risk Committee. Mr. Petty has served as a director of Enbridge since January 2001. Mr. Petty served as President and Chief Executive Officer of Telus Corporation, a Canadian telecommunications company, from November 1994 to November 1999. Mr. Petty retired in 1994 from AT&T Corporation as a Vice-President after 25 years of service. He currently serves on the Board of Directors of Fuelcell Energy Corporation.

        D.A. Westbrook was elected a director of the General Partner and Enbridge Management in October 2007 and serves on the Audit, Finance & Risk Committee. From May 2007 he has also served on the Board of Directors of Synenco Energy Inc., where he is a member of their Audit & Risk and Finance Committees. From January 2006, he has served on the Board of Directors of Knowledge Systems Inc., a privately held U.S. company. From 2001 to 2005, Mr. Westbrook served as President of BP China Gas, Power & Upstream and Vice-Chairman of the Board of Directors of Dapeng LNG, a Sino joint venture between BP subsidiaries and other Chinese companies.

        S.J.J. Letwin was elected Managing Director of the General Partner and Enbridge Management in May 2006, and is also Executive Vice President, Gas Transportation & International of Enbridge. Prior to his election he served Enbridge, the indirect parent of our General Partner, as Group Vice President, Gas Strategy & Corporate Development from April 2003; prior thereto he served Enbridge as Group Vice President, Distribution & Services from September 2000.

        T. L. McGill was elected President of the General Partner and Enbridge Management in May 2006. Mr. McGill previously served as Vice President, Commercial Activity and Business Development of the General Partner and Enbridge Management from April 2002 and Chief Operating Officer from July 2004. Prior to that time, Mr. McGill was President of Columbia Gulf Transmission Company from January 1996 to March 2002.

        S. J. Wuori was elected a director of the General Partner and Enbridge Management in January 2008 and is also the Executive Vice President of Liquids Pipelines for the General Partner and Enbridge Management. Mr. Wuori holds similar responsibilities with Enbridge. He was previously Executive Vice President, Chief Financial Officer and Corporate Development of Enbridge from 2006 to 2008, Group Vice President and Chief Financial Officer of Enbridge from 2003 to 2006 and Group Vice President, Corporate Planning and Development of Enbridge from 2001 to 2003.

        R.L. Adams was elected Vice President, U.S. Engineering and Project Execution, Liquids Pipelines of the General Partner and Enbridge Management in June 2007 prior to which he was Vice President, Operations and Technologies from April 2003. Prior to April 2003, he was Director of Technology & Operations for the General Partner and Enbridge Management from 2001, and Director of Field Operations and Technical Services and Director of Commercial Activities for Ocensa/Enbridge in Bogota, Colombia from 1997 to 2001.

        E.C. Kaitson was elected Vice President, Law and Deputy General Counsel of the General Partner and Enbridge Management in May 2007. He also currently serves as Deputy General Counsel of Enbridge. Prior to that he was Assistant Secretary of the General Partner and Enbridge Management from July 2004. He served as Corporate Secretary of the General Partner and Enbridge Management from October 2001 to July 2004. He was previously Assistant Corporate Secretary and General Counsel of Midcoast Energy Resources, Inc. from 1997 until acquired by Enbridge in May 2001.

104

        D.V. Krenz was elected Vice President of the General Partner and Enbridge Management in January 2005. Prior to that, he was President of Shell Gas Transmission, LLC (previously Shell Gas Pipelines Co.) from March 1996 to December 2004.

        J.A. Loiacono was elected Vice President, Commercial Activities, of the General Partner and Enbridge Management in July 2006. Prior to that, he was Director of Commercial Activities for the General Partner and Enbridge Management from April 2003 and commenced employment with Midcoast Energy Resources in February 2000 as an Asset Optimizer.

        M.A. Maki was elected Vice President, Finance of the General Partner and Enbridge Management in July 2002. Prior to that time, he served as Controller of the General Partner and Enbridge Management from June 2001, and prior to that, as Controller of Enbridge Pipelines from September 1999.

        A. Monaco was elected Executive Vice President, Major Projects of the General Partner and Enbridge Management in January 2008 and holds similar responsibilities with Enbridge. Prior to that Mr. Monaco was President of Enbridge Gas Distribution Inc. from September 2006, Senior Vice President, Planning & Development, Enbridge from June 2003, and Vice President, Financial Services, of Enbridge from February 2002. Mr. Monaco was Treasurer of the General Partner from February 2002 and Enbridge Management from its formation until his resignation in April 2003.

        S.J. Neyland was elected Controller of the General Partner and Enbridge Management effective September 2006. Prior to his election he served as Controller, Natural gas from January 2005, Assistant Controller from May 2004 to January 2005, and in other managerial roles in Finance and Accounting from December 2001 to May 2004. Prior to that time, Mr. Neyland was Controller of Koch Midstream Services from 1999 to 2001.

        K.C. Puckett was elected Vice President, Engineering and Operations, Gathering and Processing of the General Partner and Enbridge Management in October 2007. Prior to his election he served as General Manager of Engineering and Operations from 2004 and Manager of Operations from 2002 to 2004. Prior to that time, he served as Manager of Business Development for Sid Richardson Energy Services Company.

        J. N. Rose was elected as Treasurer of the General Partner and Enbridge Management in January 2008. He was previously Assistant Treasurer of the General Partner and Enbridge Management from July 2005. Mr. Rose is also a Director, Finance of Enbridge, a position he has held from October 2007, prior to which he was Manager, Finance from 2004. Prior to that Mr. Rose was a Vice President with Citigroup Global Corporate and Investment Bank from 2001 to 2004.

        A.M. Schneider was elected Vice President, Regulated Engineering and Operations of the General Partner and Enbridge Management in October 2007. Prior to his election he served as Director of Engineering and Operations for Regulated & Offshore and Director of Engineering Services from January 2005. Prior to that, Mr. Schneider was Vice President of Engineering and Operations for Shell Gas Transmission from December 2000.

        B.A. Stevenson was elected Corporate Secretary of the General Partner and Enbridge Management in July 2004. Between 2000 and 2004 Mr. Stevenson held management positions with Reliant Energy, Inc. and Arthur Andersen LLP. Prior to that Mr. Stevenson was General Counsel & Corporate Secretary of Alberta Natural Gas Company Ltd, a Canadian gas processing and transmission company, that was acquired by TransCanada Pipelines.

        L.A. Zupan was elected Vice President, Liquids Pipelines Operations of the General Partner and Enbridge Management in July 2004, and holds similar responsibilities with Enbridge. Mr. Zupan previously served as Vice President, Development & Services for Enbridge Pipelines from 2000.

105

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

        Section 16(a) of the Exchange Act requires our directors, executive officers and 10% beneficial owners to file with the SEC reports of ownership and changes in ownership of our equity securities and to furnish us with copies of all reports filed. To our knowledge, based solely on a review of the copies of reports furnished to us and written representations that no other reports were required, the officers, directors, and greater than 10% beneficial owners complied with all applicable filing requirements of Section 16(a) of the Exchange Act during the year.

GOVERNANCE MATTERS

        We are a "controlled company," as that term is used in NYSE Rule 303A, because all of our voting shares are owned by the General Partner. Because we are a controlled company, the NYSE listing standards do not require that we or the General Partner have a majority of independent directors or a nominating or compensation committee of the General Partner's board of directors.

        The NYSE listing standards require our Chief Executive Officer to annually certify that he is not aware of any violation by the Partnership of the NYSE corporate governance listing standards. Accordingly, this certification was provided as required to the NYSE on March 20, 2007.

CODE OF ETHICS, STATEMENT OF BUSINESS CONDUCT AND CORPORATE GOVERNANCE GUIDELINES

        We have adopted a Code of Ethics applicable to our senior financial officers, including the principal executive officer, principal financial officer and principal accounting officer of Enbridge Management. A copy of the Code of Ethics for Senior Financial Officers is available on our website at www.enbridgepartners.com and is included herein as Exhibit 14.1. We post on our website any amendments to or waivers of our Code of Ethics for Senior Financial Officers. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300, Houston, TX 77002.

        We also have a Statement of Business Conduct applicable to all of our employees, officers and directors. A copy of the Statement of Business Conduct is available on our website at www.enbridgepartners.com. We post on our website any amendments to or waivers of our Statement of Business Conduct. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300, Houston, TX 77002.

        We also have a statement of Corporate Governance Guidelines that sets forth the expectation of how the Board should function and the Board's position with respect to key corporate governance issues. A copy of the Corporate Governance Guidelines is available on our website at www.enbridgepartners.com. We post on our website any amendments to our Corporate Governance Guidelines. Additionally, this material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300, Houston, TX 77002.

AUDIT, FINANCE & RISK COMMITTEE

        Enbridge Management has an Audit, Finance & Risk Committee (the "Audit Committee") comprised of four board members who are independent as the term is used in Section 10A of the Exchange Act. None of these members is relying upon any exemptions from the foregoing independence requirements. The members of the Audit Committee are J.A. Connelly, D.A. Westbrook, M.O. Hesse, and G.K. Petty. The Audit Committee provides independent oversight with respect to our internal controls, accounting policies,

106


financial reporting, internal audit function and the report of the independent registered public accounting firm. The Audit Committee also reviews the scope and quality, including the independence and objectivity of the independent and internal auditors and the fees paid for both audit and non-audit work and makes recommendations concerning audit matters, including the engagement of the independent auditors, to the board of directors.

        The charter of the Audit Committee is available on our website at www.enbridgepartners.com. The charter of the Audit Committee complies with the listing standards of the NYSE currently applicable to us. This material is available in print, free of charge, to any person who requests the information. Persons wishing to obtain this printed material should submit a request to Corporate Secretary, c/o Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300, Houston, TX 77002.

        Enbridge Management's board of directors has determined that J.A. Connelly and M.O. Hesse qualify as "Audit Committee financial experts" as defined in Item 407(d)(ii) of SEC Regulation S-K. Each of the members of the Audit, Finance and Risk Committee is independent as defined by Section 303A of the listing standards of the NYSE.

        Ms. Hesse also serves on the Audit Committees of the General Partner, Enbridge Management, Amec plc., Mutual Trust Financial Group and of Terra Industries, Inc. In compliance with the provisions of the Audit, Finance & Risk Committee Charter, the boards of directors of the General Partner and of Enbridge Management have determined that Ms. Hesse's simultaneous service on such audit committees does not impair her ability to effectively serve on the Audit, Finance & Risk Committee.

        Mr. Petty also serves on the Audit Committees of the General Partner, Enbridge Management, Fuel Cell Energy, Inc. and of Enbridge Inc. In compliance with the provisions of the Audit, Finance & Risk Committee Charter, the boards of directors of the General Partner and of Enbridge Management have determined that Mr. Petty's simultaneous service on such audit committees does not impair his ability to effectively serve on the Audit, Finance & Risk Committee.

        Enbridge Management's Audit Committee has established procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. Persons wishing to communicate with our Audit Committee may do so by writing in care of Chairman, Audit Committee, c/o Enbridge Energy Management, L.L.C., 1100 Louisiana, Suite 3300, Houston, TX 77002.

EXECUTIVE SESSIONS OF NON-MANAGEMENT DIRECTORS

        The independent directors of Enbridge Management meet at regularly scheduled executive sessions without management. M.O. Hesse serves as the presiding director at those executive sessions. Persons wishing to communicate with the Company's independent directors may do so by writing in care of Chairman, Board of Directors, Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300, Houston, TX 77002.

107

Item 11.    Executive Compensation

COMPENSATION DISCUSSION AND ANALYSIS

        We are a master limited partnership and we do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. We obtain managerial, administrative and operational services from our general partner and Enbridge pursuant to service agreements among us, Enbridge Management, and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse our general partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us.

        The compensation policies and philosophy of Enbridge govern the types and amount of compensation granted to each of the Named Executive Officers, or NEOs. Since these policies and philosophy are those of Enbridge, we refer you to a discussion of those items as set forth in the Executive Compensation section of the Enbridge "Management Information Circular" on the Enbridge website at www.enbridge.com. The Enbridge "Management Information Circular" is produced by Enbridge pursuant to Canadian securities regulations and is not incorporated into this document by reference or deemed furnished or filed by us under the Exchange Act; rather the reference is to provide our investors with an understanding of the compensation policies and philosophy of the ultimate parent of our general partner.

        The boards of directors of Enbridge Management and our General Partner do not have separate compensation committees, nor do they have responsibility for approving the elements of compensation presented in the tables which follow this discussion. The boards of directors of Enbridge Management and our general partner do have responsibility for evaluating and determining the reasonableness of the total amount we are charged for managerial, administrative and operational support, including compensation of the NEOs, provided by Enbridge and its affiliates, including our general partner.

        All U.S.-domiciled employees of Enbridge are directly employed by its subsidiary, Enbridge Employee Services, Inc., which we refer to as EES. In connection with our annual budget process, we calculate an average "Budgeted Allocation Rate," which represents an estimated average of the percentage of time expected will be spent by each of our NEOs on our business during the succeeding year. Those estimates are revised each year based on historical experience. The average Budgeted Allocation Rate was 84% for 2007 and has been set at approximately 85% for 2008. EES' salary costs are allocated to us based on the percentage of time spent by EES employees on our behalf compared with the total time of all EES employees. We are allocated a portion of the equity-based compensation expense as determined in accordance with U.S. GAAP. Pension expenses of EES (other than expenses under Enbridge's nonqualified supplemental pension plan for U.S.-domiciled employees, which we refer to as the SPP) are allocated to us based on the proportion that the total headcount of EES employees assigned to us bears to the total headcount of EES. For this purpose, an employee of EES is deemed to be assigned to us if he or she works on assets we own. Pension expenses of EES attributable to the SPP are allocated to us based upon the average Budgeted Allocation Rate. EES allocates to us that portion of its compensation expense for Enbridge's Short Term Incentive Plan, a non-equity performance-based incentive plan, equal to the total salaries of employees who perform work for us multiplied by the average Budgeted Allocation Rate divided by EES' total salary expense.

        We are a partnership and not a corporation for U.S. federal income tax purposes, and therefore, are not subject to the executive compensation tax deductible limitations of Internal Revenue Code §162(m). Accordingly, none of the compensation paid to our NEOs is subject to limitation. The compensation of our Named Executive Officers included in the tables below is established by a committee of the board of directors of Enbridge. We have included in the following tables the full amount of compensation and related benefits provided for the NEOs for 2007 and 2006, together with the approximate amount of compensation cost allocated to us for the years ended December 31, 2007 and 2006.

108


SUMMARY COMPENSATION TABLE


Name and Principal Position
   Year
   Salary
($)
   Bonus
($)
   Stock
Awards(1)
($)
   Option
Awards(2)
($)
   Non-Equity
Incentive
Plan
Compensation(3)
($)
   Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings
($)
   All
Other
Compensation(4)
($)
   Total
($)
   Approximate
Amount
Allocated to
Enbridge
Energy
Partners,
L.P.
($)

S.J.J. Letwin(5)
Managing Director
 (Principal Executive Officer)		   2007
2006		   483,750
457,257		   —
—		   116,820
108,600		   570,647
316,259		   450,000
450,000		   335,000
208,000		   127,310
185,871		   2,083,527
1,725,987		   $
 1,507,502
—
T.L. McGill
President		   2007
2006		   323,631
290,000		   —
—		   41,536
38,535		   148,725
191,599		   241,320
200,000		   128,000
103,000		   50,039
39,659		   933,251
862,793		     815,977
758,806
J. R. Bird(6)
Executive Vice President–Liquids Pipelines		   2007
2006		   468,692
419,937		   —
—		   116,820
98,090		   476,614
495,433		   465,203
440,878		   988,000
512,000		   88,167
75,042		   2,603,496
2,041,380		     269,386
190,000
M.A. Maki
Vice President–Finance
 (Principal Financial Officer)		   2007
2006		   258,681
212,500		   —
—		   27,258
22,187		   67,217
74,014		   161,170
140,000		   103,000
71,000		   38,856
35,056		   656,182
554,757		     577,011
480,703
R.L. Adams
Vice President–Operations and Technology		   2007
2006		   220,779
189,375		   —
—		   22,066
19,852		   53,895
50,677		   135,000
117,000		   78,000
55,000		   96,469
33,543		   606,209
465,447		     564,365
402,909
(1)
The 2007 expense associated with Performance Stock Units (PSUs) is reflected in this column and is measured based on the number of respective units granted, the percentage vested (33%) and the market value, representing the volume weighted average closing price of an Enbridge share as quoted on the NYSE for U.S. dollar (USD) denominated PSUs and the Toronto Stock Exchange, or TSX, for Canadian dollar (CAD) denominated PSUs for the 20 consecutive days prior to January 1, 2008. Beginning in 2007, U.S. domiciled NEOs were granted PSUs denominated in USD with a market value at December 31, 2007 of $38.94 per unit computed as described in the preceding sentence. Canadian domiciled NEOs are granted PSUs denominated in CAD, the market value of the 2007 PSUs has been converted to USD at December 31, 2007 using the market value computed for U.S. domiciled employees. The 2006 expense for PSUs grants is measured based on the number of respective units granted, the percentage vested (33%) and the market value, representing the weighted average closing price of an Enbridge share as quoted on the Toronto Stock Exchange, or TSX for the 20 consecutive days prior to January 1, 2007, or $39.73 CAD, since all 2006 PSU grants are denominated in CAD. The expense has been converted to United States dollars, or USD, using the average exchange rate during 2006 of $1.1341 CAD = $1 USD. The PSUs were granted on January 1, 2007 and 2006, respectively.

(2)
The annual expenses for option awards that are granted under the Enbridge Incentive Stock Option Plan (2002) ("ISOP") and the Performance Stock Option Plan (2007) ("PSOP") are determined by computing the fair value of the options under FAS 123(R) on the grant date using the Black-Scholes option pricing model with the following assumptions for the indicated grant year:

 
   ISOP
   PSOP
Assumption
  2007
   2006
   2007
   2006
Expected option term in years   6   8   8   NA
Expected volatility   18.1 % 19.0 % 13.6 % NA
Expected dividend yield   3.22 % 3.23 % 3.57 % NA
Risk-free interest rate   4.11 % 4.16 % 4.38 % NA

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   ISOP
   PSOP
 
   2007
   2006
   2007
   2006
Exercise price in CAD   $ 38.26   $ 36.47   $ 36.57   NA
Exercise price in USD   $ 32.59   $ 31.58   $ 34.03   NA
Grant date exchange rate for $1 USD   $ 1.1740   $ 1.1548   $ 1.0746   NA
 
 
   ISOP
   PSOP
 
   2007
   2006
   2007
   2006
Vesting period     4     4     5   NA
Option fair value on grant date in CAD   $ 6.16   $ 6.28   $ 3.40   NA
Option fair value on grant date in USD   $ 5.25   $ 5.54   $ 3.16   NA
Average exchange rate for $1 USD   $ 1.1740   $ 1.1341   $ 1.0750   NA
(3)
Non-equity incentive plan compensation represents awards that are paid in February for amounts that are earned in the immediately preceding fiscal year under the Enbridge Short Term Incentive Plan, or STIP. The Enbridge STIP is a performance-based plan where measurement metrics are established at the beginning of each fiscal year that promote the achievement of financial, safety, corporate governance and individual goals. The amount presented for Mr. Bird represents an award of $500,000 CAD, which was converted to USD using the weighted average exchange rate of $1.0748 CAD = $1 USD. All other amounts presented in this column represent USD denominated STIP awards.

(4)
The table which follows labeled "All Other Compensation" sets forth the elements comprising the amounts presented in this column.

(5)
Mr. Letwin relocated to the United States on May 1, 2006, and became Managing Director of our general partner and Enbridge Management. Mr. Letwin is also an executive officer of Enbridge with responsibility for other Enbridge operations in addition to those of our general partner, Enbridge Management, and us, which he assumed in May 2006. We have included the full amount of Mr. Letwin's compensation in the summary compensation table. However, we were not charged the cost of Mr. Letwin's compensation for the period from January 1, 2006 through December 31, 2006, since the allocation to us of compensation to Mr. Letwin was not contemplated in our budget. As a result, Mr. Letwin's compensation was borne by other Enbridge affiliates. For the year ended December 31, 2006, we used a weighted average exchange rate of $1.1519 CAD = $1 USD to convert the compensation costs to USD for Mr. Letwin, which represents the weighted average exchange rate for the period from May 1, 2006 through December 31, 2006. The costs associated with the PSU's and options Mr. Letwin was granted in 2006 were borne by Enbridge and other affiliates where he is also an officer because the grants occurred prior to his becoming managing director of our general partner and Enbridge Management.

(6)
Mr. Bird is also an executive officer of Enbridge with responsibility for other affiliates of Enbridge in addition to those for our general partner and Enbridge Management. Mr. Bird is compensated by affiliates of Enbridge in CAD which we have converted to USD using the weighted average exchange rates for the years ended December 31, 2007 and 2006 of $1.0748 CAD = $1 USD and $1.1341 CAD = $1.0 USD, respectively. The costs associated with the PSU's and options Mr. Bird was granted in 2007 and 2006 were borne by Enbridge and other affiliates where he is also an officer. We are allocated a portion of the remaining elements of Mr. Bird's compensation based on the approximate percentage of time he devotes to us and Enbridge Management. In January 2008, Mr. Bird assumed other responsibilities with Enbridge and ceased being an NEO of Enbridge Management and the General Partner.

110


ALL OTHER COMPENSATION
(For the years ended December 31, 2007 and 2006)


Name
   Year
   Flexible
Benefits(1)
   401(k)
Matching
Contribution(2)
   Relocation
Allowance
   Mortgage
Interest
Payments
   Dividends
Paid on
PSUs
   Other
Benefits(3)
   Total

S.J.J. Letwin   2007
2006		   $
 35,000
35,169		   $
 11,250
11,000		   $
 —
77,500		   $
 40,321
25,701		   $
 36,307
29,706		   $
 4,432
6,795		   $
 127,310
185,871
T.L. McGill   2007
2006		     20,000
20,000		     11,250
11,000		     —
—		     —
—		     11,204
6,434		     7,585
2,225		     50,039
39,659
J.R. Bird   2007
2006		     52,081
48,482		     —
—		     —
—		     —
—		     32,045
24,236		     4,041
2,324		     88,167
75,042
M.A. Maki   2007
2006		     20,000
20,000		     11,250
10,625		     —
—		     —
—		     7,343
4,214		     263
217		     38,856
35,056
R.L. Adams   2007
2006		     20,000
20,000		     11,039
9,469		     58,722
—		     —
—		     6,493
3,882		     215
192		     96,469
33,543
(1)
Flexible benefits for our U.S. domiciled NEOs represent a perquisite allowance that is paid in cash as additional compensation. Our NEOs domiciled in Canada receive flexible benefits based on their family status and base salary. For our NEOs that are domiciled in Canada, the flexible benefits can be used to purchase additional benefits, paid in cash, or be applied as contributions to the Enbridge Stock Purchase and Savings Plan; or (b) paid as additional compensation. The amounts reported in this column include the net flexible benefits that Mr. Bird and Mr. Letwin (2006) applied to the Enbridge Stock Purchase and Savings Plan.

(2)
Our NEOs that are domiciled in the United States and participate in the Enbridge Employee Services, Inc. Savings Plan (the "401(k) Plan") may contribute up to 50 percent of their base salary which is matched up to 5 percent by Enbridge. Both individual and matching contributions are subject to limits established by the Internal Revenue Service. Enbridge contributions are used to purchase Enbridge shares at market value and employee contributions may be used to purchase Enbridge shares or 22 designated funds.

(3)
Other benefits include professional financial services, term life insurance premiums, parking, and home security and internet services.

        We do not maintain any compensation plans for the benefit of the NEOs under which equity interests in Enbridge Management or the Partnership may be awarded. However, Enbridge allocates to us the compensation expense it recognizes under FAS 123(R) in connection with recording the fair value of its restricted stock units and outstanding stock options granted to certain of our officers, including the NEOs. The costs we are charged with respect to option grants represent a portion of the costs determined in accordance with U.S. GAAP.

        The performance stock units are granted to the NEOs pursuant to the Enbridge Inc. Performance Stock Unit Plan and stock options are granted pursuant to the Enbridge Incentive Stock Option Plan (2002) and the Performance Stock Option Plan (2007). Awards under these plans provide long-term incentive and are administered by the Human Resources & Compensation Committee of Enbridge. The performance stock units granted from 2004 through 2006 and stock option grants are denominated in CAD. The performance stock units granted in 2007 to our U.S.-domiciled NEOs are denominated in USD while those granted to NEOs domiciled in Canada are denominated in Canadian dollars. The following two tables set forth information concerning performance stock units and stock options outstanding at

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December 31, 2007, and the number of awards vested and exercised during the year ended December 31, 2007, by each of the NEOs:


GRANTS OF PLAN-BASED AWARDS


 
    
    
    
    
    
    
    
    
    
   All
Other
Stock
Awards:
Number
of
Shares
of Stock
or Units
(#)
(i)
    
    
    
 
    
    
    
    
    
    
    
    
    
   All Other
Option
Awards:
Number
of
Securities
Underlying
Options(3)
(#)
(j)
    
    
 
    
    
    
   Estimated Future Payouts
Under non-Equity Incentive
Plan Awards(4)
   Estimated Future Payouts
Under Equity Incentive Plan
Awards(2)
    
    
 
    
    
    
   Exercise
or Base
Price of
Option
Awards(3)
($/Sh)
(k)
   Grant Date
Fair
Value of
Stock and
Option
Awards(2)(3)
($)
(l)
 
    
    
    
  

Name
(a)
   Plan
Name(1)
   Approval
Date
(b)
   Grant
Date
(b)
   Threshold
($)
(c)
   Target
($)
(d)
   Maximum
($)
(e)
   Threshold
(#)
(f)
   Target
(#)
(g)
   Maximum
(#)
(h)

S.J.J. Letwin   PSUP
ISOP
PSOP
STIP		   30-Jan-07
30-Jan-07
31-Jul-07
30-Jan-07		   1-Jan-07
9-Feb-07
15-Aug-07
28-Feb-07		   —
—
—
—		   —
—
—
245,000		   —
—
—
490,000		   360
—

—		   9,000
—

—		   18,000
—

—		   —
—
—
—		   —
45,000
330,000
—		   —
32.59
34.03
—		   312,570
236,250
1,044,109
—
T.L. McGill   PSUP
ISOP
STIP		   30-Jan-07
30-Jan-07
30-Jan-07		   1-Jan-07
9-Feb-07
28-Feb-07		   —
—
—		   —
—
127,680		   —
—
255,360		   128
—
—		   3,200
—
—		   6,400
—
—		   —
—
—		   —
16,400
—		   —
32.59
—		   111,136
86,100
—
J.R. Bird   PSUP
ISOP
PSOP
STIP		   30-Jan-07
30-Jan-07
31-Jul-07
30-Jan-07		   1-Jan-07
9-Feb-07
15-Aug-07
28-Feb-07		   —
—
—
—		   —
—
—
237,253		   —
—
—
474,507		   360
—
—
—		   9,000
—
—
—		   18,000
—
—
—		   —
—
—
—		   —
45,000
330,000
—		   —
32.59
34.03
—		   312,570
236,250
1,044,109
—
M.A. Maki   PSUP
ISOP
STIP		   30-Jan-07
30-Jan-07
30-Jan-07		   1-Jan-07
9-Feb-07
28-Feb-07		   —
—
—		   —
—
88,410		   —
—
176,820		   84
—
—		   2,100
—
—		   4,200
—
—		   —
—
—		   —
11,500
—		   —
32.59
—		   72,933
60,375
—
R.L. Adams   PSUP
ISOP
STIP		   30-Jan-07
30-Jan-07
30-Jan-07		   1-Jan-07
9-Feb-07
28-Feb-07		   —
—
—		   —
—
78,750		   —
—
157,500		   68
—
—		   1,700
—
—		   3,400
—
—		   —
—
—		   —
9,500
—		   —
32.59
—		   59,041
49,875
—
(1)
The abbreviated plan names are defined as follows:

    a.
    PSUP refers to the Enbridge Performance Stock Unit Plan, an equity-based incentive plan.

    b.
    ISOP refers to the Enbridge Incentive Stock Option Plan, a qualified stock option plan.

    c.
    PSOP refers to the Enbridge Performance Stock Option Plan (2007), a performance-based, incentive stock option plan.

    d.
    STIP refers to the Enbridge Short Term Incentive Plan, a non-equity performance-based incentive plan.

(2)
Our NEOs are eligible to receive annual grants of Performance Stock Units, or PSUs, under the Performance Stock Unit Plan, or PSUP, an equity-based, long-term incentive plan, administered by a committee of the board of directors of Enbridge. The initial value of each of these PSUs on the grant date is equivalent to the weighted average closing price of one Enbridge share as quoted on the New York Stock Exchange for the 20 days immediately preceding the start of the performance period. The initial PSUs granted are increased for quarterly dividends paid during the three-year period on an Enbridge share. Awards under the 2007 PSUP are paid out in cash at the end of a three-year performance cycle based on: (1) an earnings per share, or EPS target for Enbridge based on the long range plan of the organization and (2) the price to earnings ratio of an Enbridge share relative to a defined group of peer organizations established in advance by a committee of the board of directors of Enbridge. The performance measures for grants awarded from 2004 through 2006 are based on (1) the market value of an Enbridge share at the end of the three-year period; and (2) the total shareholder return for Enbridge over a three-year period in relation to a peer group of companies established in advance by a committee of the board of directors of Enbridge. Payments under the PSUP may be increased up to 200 percent of the original award when Enbridge outperforms its peer group. If Enbridge fails to meet threshold performance levels, no payments are made under the PSUP. Dividends are paid on the PSUs which are invested in additional PSUs at the then current market price for one share of Enbridge common stock which are not included in the estimated future payout amounts, but have been included as other compensation in the Summary Compensation table. Enbridge does not issue any shares in connection with the PSUP.
(3)
The Enbridge Incentive Stock Option Plan (2002) is administered by a committee of the Enbridge board of directors and if an option is issued during a trading blackout period, the exercise price of an option grant is determined as the weighted average trading price of an Enbridge share on the Toronto Stock Exchange for the three trading days immediately prior to the effective date of the option. In the event an option grant is issued during a period a trading blackout is not in effect, the exercise price of the option grant is equal to the last reported sales price on the Toronto Stock Exchange for the day immediately preceding the grant date. During 2007, each of the NEOs received grants of Enbridge incentive stock options that upon exercise may be exchanged for an equivalent number of shares of Enbridge common stock. The exercise price of the incentive stock options at the time of grant was $38.26 CAD which has been converted into USD using an exchange rate of $1.1740 CAD per $1 USD, representing the noon buying rate in New York for transfers of CAD on the grant date of February 9, 2007.

112

(4)
The Enbridge Performance Stock Option Plan (2007) is administered by a committee of the Enbridge board of directors and if an option is issued during a trading blackout period, the exercise price of an option grant is determined as the weighted average trading price of an Enbridge share on the Toronto Stock Exchange for the five trading days immediately prior to the effective date of the option. In the event an option grant is issued during a period a trading blackout is not in effect, the exercise price of the option grant is equal to the last reported sales price on the Toronto Stock Exchange for the day immediately preceding the grant date. Performance-based stock options, or PBSOs, are similar to the incentive stock options, except that the quantities become exercisable subject to both the achievement of specified share price targets and time requirements. One half of the PBSOs become exercisable if the first share price hurdle is achieved and 100% of the grant becomes exercisable if the second share price hurdle is achieved within a 61/2 year time period. The term of each grant is 8 years provided the performance criteria are met. PBSOs are granted on an infrequent basis and provide the eligible NEO the opportunity to acquire one Enbridge Share for each option held when the specified time and share price targets are met. During 2007, Messrs. Letwin and Bird each received grants of Enbridge performance stock options that upon exercise may be exchanged for an equivalent number of shares of Enbridge common stock. The exercise price of the PBSOs at the time of grant was $36.57 CAD which has been converted into USD using an exchange rate of $1.0746 CAD per $1 USD, representing the noon buying rate in New York for transfers of CAD on the grant date of August 15, 2007.

(5)
The estimated future payouts under the Enbridge STIP are determined for the indicated fiscal year, based upon achievement of performance goals established at the beginning of the fiscal year for each of the NEOs. The payouts earned under the STIP for each fiscal year are generally paid to the NEO on the last business day of February of the year following the fiscal year in which the payout is earned. The performance goals include pre-determined financial, safety, corporate governance and operational goals that are aligned with the business objectives for Enbridge and the business unit(s) to which the NEOs are assigned, in addition to individual performance objectives. Based upon the level achieved in meeting the pre-determined objectives, a multiple is determined that can vary from a low of zero, if the level of achievement is significantly below the stated objectives, to a high of two, if the level of achievement significantly exceeds the stated objective, with the mid-point or target representing achievement of 100 percent of the pre-established goals. The multiple is then applied to the bonus level, represented as a percentage of base salary, for each NEO. The STIP targets for each NEO expressed as a percentage of salary for 2007 is as follows:


 
 
   Threshold
   Target
   Maximum
  

 
S.J.J. Letwin   —   50 % 100 %
 
T.L. McGill   —   40 % 80 %
 
J.R. Bird   —   50 % 100 %
 
M.A. Maki   —   35 % 70 %
 
R.L. Adams   —   35 % 70 %
 

113


OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END


 
   Option Awards
   Stock Awards
 
  

Name
(a)
   Number of Securities Underlying Unexercised Options
(#)
Exercisable
(b)
   Number of Securities Underlying Unexercised Options
(#)
Unexercisable
(1)(2)
(c)
   Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options
(#)
(d)
   Option Exercise Price(4)
($)
(e)
   Option Expiration Date(1)
(f)
   Number of Shares or Units of Stock That Have Not Vested
(#)
(g)
   Market Value of Shares or Units of Stock That Have Not Vested
($)
(h)
   Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested(3)
(#)
(i)
   Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
($)
(j)

S.J.J. Letwin   —
26,200
—
13,425
—		   11,000
26,200
330,000
40,275
45,000		   —
—
—
—
—		   19.30
25.49
34.03
31.58
32.59		   4-Feb-14
3-Feb-15
15-Aug-15
13-Feb-16
9-Feb-17		   —
—		   —
—		   9,921
9,304		   401,117
376,159
T.L. McGill   46,400
30,000
10,200
4,725
—		   —
10,000
10,200
14,175
16,400		   —
—
—
—
—		   13.69
19.30
25.49
31.58
32.59		   6-Feb-13
4-Feb-14
3-Feb-15
13-Feb-16
9-Feb-17		   —
—		   —
—		   3,520
3,308		   142,332
133,746
J.R. Bird   200,000(2)
40,000
25,050
20,700
—
12,075
—		   —
—
8,350
20,700
330,000
36,225
45,000		   —
—
—
—
—
—
—		   14.63
13.69
19.30
25.49
34.03
31.58
32.59		   16-Sep-10
6-Feb-13
4-Feb-14
3-Feb-15
15-Aug-15
13-Feb-16
9-Feb-17		   —
—		   —
—		   8,961
9,304		   362,300
376,176
M.A. Maki   7,500
16,000
33,400
22,500
5,700
2,775
—		   —
—
—
7,500
5,700
8,325
11,500		   —
—
—
—
—
—
—		   12.43
13.68
13.69
19.30
25.49
31.58
32.59		   21-Feb-11
5-Feb-12
6-Feb-13
4-Feb-14
3-Feb-15
13-Feb-16
9-Feb-17		   —
—		   —
—		   2,027
2,171		   81,949
87,771
R.L. Adams   4,500
10,000
5,400
2,500
—		   —
5,000
5,400
7,500
9,500		   —
—
—
—
—		   13.69
19.30
25.49
31.58
32.59		   6-Feb-13
4-Feb-14
3-Feb-15
13-Feb-16
9-Feb-17		   —
—		   —
—		   1,814
1,757		   73,323
71,052
(1)
Each incentive stock option award has a ten year term and vests pro rata as to one-fourth of the option award beginning on the first anniversary of the grant date thus, the vesting dates for each of the option awards in this table can be calculated accordingly. As an example, for Mr. Letwin's grant that expires on February 6, 2013, the grant date would be ten years prior or February 6, 2003 and as a result, the remaining unexercisable amounts become fully vested on February 6, 2007 representing four years following the grant date.

(2)
Performance-based stock options, or PBSOs, were provided to certain of our NEOs on September 16, 2002 and August 15, 2007 and are similar to the incentive stock options, except that the quantity that become exercisable are subject to both time and performance requirements. PBSOs are granted on an infrequent basis and provide the eligible NEO the opportunity to acquire one Enbridge Share for each option held when the specified time and performance conditions are met. The PBSOs granted September 16, 2002, became exercisable, as to 50 percent of the grant, when the price of an Enbridge Share exceeded $30.50 for 20 consecutive trading days during the period September 16, 2002 to September 16, 2007, and became exercisable as to 100 percent when the price of an Enbridge share exceeded $35.50 CAD for 20 consecutive trading days during the same period. As a result of achieving the established performance criteria, the initial five year term of the options was extended to eight years expiring on September 16, 2010. In addition to the performance hurdles, the PBSOs are also time vested 20% annually over 5 years. As of December 31, 2007, 100 percent of the PBSOs granted September 16, 2002, had vested and were exercisable and none of the PBSOs granted August 15, 2007, were vested or exercisable.

(3)
The unearned shares, units or other rights that have not vested under stock awards represent PSUs for which the performance criteria discussed in footnote number 2 of the Grants of Plan-Based Awards table have not been achieved. The PSUs become vested upon achieving the established performance criteria as set forth in the aforementioned footnote.

114

(4)
The exercise prices of the ISDs and PBSOs are denominated in CAD, which have been converted to USD using the exchange rate on the grant date as set forth below:

Option Grant Date
   Option Exercise Price CAD
   Exchange Rate USD/CAD
   Option Exercise Price USD
February 21, 2001   $ 19.1000   $ 0.6508   $ 12.4303
February 5, 2002     21.8500     0.6259     13.6759
September 16, 2002     23.1500     0.6319     14.6285
February 6, 2003     20.8250     0.6572     13.6862
February 4, 2004     25.7200     0.7504     19.3003
February 3, 2005     31.6800     0.8046     25.4897
February 13, 2006     36.4700     0.8660     31.5830
February 9, 2007     38.2600     0.8519     32.5937
August 15, 2007     36.5700     0.9306     34.0320


OPTION EXERCISES AND STOCK VESTED


 
   Option Awards
   Stock Awards
 
  

Name
   Number of Shares Acquired on Exercise
(#)
   Value Realized on Exercise
($)
   Number of Shares Acquired on Vesting(1)
(#)
   Value Realized on Vesting(2)
($)

S.J.J. Letwin   71,000   955,832.74   20,702.32   $ 392,467.47
T.L. McGill   —   —   3,166.67     89,124.18
J.R. Bird   —   —   16,038.10     307,147.03
M.A. Maki   —   —   2,353.01     66,224.21
R.L. Adams   —   —   2,221.07     62,510.71
(1)
The number of shares acquired on vesting represent the number of PSUs issued in 2004 that matured on March 7, 2007, and in 2005 that matured on December 31, 2007. As discussed above in footnote number 2 of the Grants of Plan-Based Awards table, no shares are issued with respect to the PSUs that become vested rather cash is paid in an amount based on the value of an Enbridge share at the maturity date and the level of achievement of the established performance goals.

(2)
The value realized on vesting has been converted to USD using an exchange rate of $1.1786 CAD = $1 USD for the PSUs that matured on March 7, 2007, and an exchange rate of $0.9881 CAD = $1 USD for the PSUs that matured on December 31, 2007. These exchange rates represent the noon buying rate in New York for transfers of CAD on the respective maturity dates.

(3)
The value realized on exercise of options by Mr. Letwin has been converted to USD using an exchange rate of $0.9818 CAD = $1 USD for 40,000 options exercised on October 5, 2007 and an exchange rate of $1.0194 CAD = $1 USD for 31,000 options exercised on September 18, 2007.

Pension Plan

        Enbridge sponsors two basic pension plans, the Retirement Plan for Employees' Annuity Plan ("EI RPP") and the Enbridge Employee Services, Inc. Employees' Annuity Plan ("QPP"), which provide defined pension benefits and cover employees in Canada and the United States, respectively. Both plans are non-contributory. Enbridge also sponsors supplemental nonqualified retirement plans in both Canada ("EI SPP") and the United States ("US SPP"), which provide pension benefits for the NEOs in excess of the tax-qualified plans' limits. We collectively refer to the EI RPP, the QPP, the EI SPP and the US SPP as the "Pension Plans." Retirement benefits under the Pension Plans are based on the employees' years of service and final average remuneration with an offset for Social Security benefits. These benefits are partially indexed to inflation after a named executive officer's retirement.

        For service prior to January 1, 2000, the Pension Plans provide a yearly pension payable after age 60 in the normal form (60 percent joint and last survivor) equal to: (a) 1.6 percent of the average of the participant's highest annual salary during three consecutive years out of the last ten years of credited service multiplied by (b) the number of credited years of service. The pension is offset, after age 65, by 50 percent of the participant's Social Security benefit, prorated by years in which the participant has both

115


credited service and Social Security coverage. An unreduced pension is payable if retirement is after age 55 with 30 or more years of service, or after age 60. Early retirement reductions apply if a participant retires and does not meet these requirements. Retirement benefits paid from the Plan are indexed at 50 percent of the annual increase in the consumer price index.

        For service after December 31, 1999, the Pension Plans provide for senior management employees, including the NEOs, a yearly pension payable after age 60 in the normal form (60 percent joint and last survivor) equal to: (a) 2 percent of the sum of (i) the average of the participant's highest annual base salary during three consecutive years out of the last ten years of credited service and (ii) the average of the participant's three highest annual performance bonus periods, represented in each period by 50 percent of the actual bonus paid, in respect of the last five years of credited service, multiplied by (b) the number of credited years of service. An unreduced pension is payable if retirement is after age 55 with 30 or more years of service, or after age 60. Early retirement reductions apply if a participant retires and does not meet these requirements. Retirement benefits paid from the Plan are indexed at 50 percent of the annual increase in the consumer price index.

        The table illustrates the total annual pension entitlements assuming the eligibility requirements for an unreduced pension have been satisfied. The present value of the accumulated benefits has been determined under the accrued benefit valuation method with the following assumptions:

Discount rate   6.00% at year end 2007
Salaries   Current
Inflation   2.50% per year
Retirement age   60
Terminations   None
Mortality    
  Pre-retirement   None
  Post-retirement   RP-2000 Projected to 2005

        Plan benefits that exceed maximum pension rules applicable to registered plan benefits are paid from the Enbridge supplemental pension plans. Other trusteed pension plans, with varying contribution formulae and benefits, cover the balance of employees.

        Mr. Bird accumulated pension credits equal to 2.0% for each year of service from his date of employment until January 1, 2000 and 3.26% for each year of service thereafter to his sixtieth birthday. Mr. Letwin was granted six additional years of credited service on his employment date based on the pension formula applicable for service prior to January 1, 2000.

116


PENSION BENEFITS


Name
(a)
   Plan Name
(b)
   Number Of Years Credited Service
(#)
(c)
   Present Value of Accumulated Benefit
($)
(d)
   Payments During Last Fiscal Year
($)
(e)

S.J.J. Letwin   EI RPP
EI SPP
QPP
USSPP		   7.08
13.08
1.67
1.67		   177,000
1,460,000
63,000
163,000		   —
—
—
—
T.L. McGill   US QPP
US SPP		   5.50
5.83		   90,000
389,000		   —
—
J.R. Bird   EI RPP
EI SPP		   12.92
12.92		   431,000
3,120,000		   —
—
M.A. Maki   EI RPP
EI SPP
US QPP
US SPP		   1.92
1.92
19.40
19.40		   32,000
36,000
462,000
100,000		   —
—
—
—
R.L. Adams   US QPP
US SPP		   20.58
6.50		   451,000
85,000		   —
—

Employment and Severance Agreements

        Enbridge has employment and severance agreements in place with each of Stephen J. J. Letwin, Managing Director and Chief Executive Officer of Enbridge Management and the General Partner, and J. Richard Bird, Executive Vice President—Liquids Pipelines of Enbridge Management and the General Partner. The agreements took effect on April 14, 2003 and were amended effective June 24, 2004. The agreements continue in effect until the earlier of (i) the applicable executive's voluntary retirement in accordance with the retirement policies established for senior employees of Enbridge, (ii) such executive's voluntary resignation, other than a voluntary resignation within 90 days after a "constructive dismissal" (as defined in the agreements) or within one year following a change of control of Enbridge, (iii) termination based on death or disability of such executive, or (iv) termination of such executive's employment by Enbridge.

        The agreements provide that Enbridge will pay severance benefits to each of Mr. Letwin and Mr. Bird if (i) his employment is involuntarily terminated without cause or because of his disability, (ii) he elects to terminate his employment within 60 days of the first anniversary of the occurrence of a change of control of Enbridge, or (iii) he elects to terminate his employment within 60 days following constructive dismissal. In each such instance, and subject to the terms of the agreements, Enbridge will pay to the applicable executive the following:

117

        The agreements also provide that each of Mr. Letwin and Mr. Bird are entitled to certain benefits, including two years of additional service added to the service already accrued at the date of his termination under the Enbridge defined benefit pension plan and supplemental benefit pension plan and cash payment of certain non-vested options, if any, that are cancelled under the Incentive Stock Option Plan (ISOP) as a consequence of termination of his employment. In the case of options granted pursuant to the ISOP, the payment is calculated based on the in-the-money value of the applicable executive's non-vested option at the date of his termination.

        According to the agreements, a "change of control" means:

118

        Each of Mr. Letwin and Mr. Bird is subject during his employment (and for two years thereafter with regard to disclosure of confidential information) to restrictions on (i) any practice or business in competition with Enbridge or its affiliates and (ii) disclosure of the confidential information of Enbridge or its affiliates.

        In the event of involuntary termination without cause or because of disability or voluntary termination within 60 days of the first anniversary of the occurrence of a change of control of Enbridge or within 60 days following constructive dismissal, Enbridge would owe approximately $5 million and $6 million to Mr. Letwin and Mr. Bird, respectively. Such amounts assume that termination was effective as of December 31, 2007, and as a result include amounts earned through such time and are estimates of the amounts which would be paid out to each of Mr. Letwin and Mr. Bird upon termination under such circumstances. The actual amounts to be paid out can only be determined at the time of such executive's separation from Enbridge.

119

Director Compensation

        As a partnership, we are managed by Enbridge Management, as the delegate of Enbridge Energy Company, Inc., our general partner. The boards of directors of Enbridge Management and our general partner, which are comprised of the same persons, perform for us the functions of a board of directors of a business corporation. We are allocated 100 percent of the director compensation of these board members. Enbridge employees who are members of the boards of directors of the General Partner or Enbridge Management do not receive any additional compensation for serving in those capacities.

        As of January 1, 2006, the Director Compensation Plan was amended to increase the annual retainer to $75,000 and additional meeting fees were eliminated. The retainers paid to directors serving as the chairman of the boards and chairman of the audit committees will remain at current levels. The out of state travel fee will be increased to $1,500 per meeting. As part of this change to the Director Compensation Plan, the directors voted to amend the Corporate Governance Guidelines to incorporate an expectation that independent directors will hold a personal investment in either or both of us or Enbridge Management, of at least two times the annual board retainer, which currently would be $150,000 (i.e., 2 X $75,000 = $150,000). Directors would be expected to achieve the foregoing level of equity ownership by the later of January 1, 2011 or five years from the date they became a director.


DIRECTOR COMPENSATION


Name
   Fees Earned or Paid in Cash
($)
   Stock Awards
($)
   Option Awards
($)
   Non-Equity Incentive Plan Compensation
($)
   Change in Pension Value and Nonqualified Deferred Compensation Earnings
($)
   All Other Compensation
($)
   Total
($)

J.A. Connelly
 Audit Committee Chairman		   84,000   —   —   —   —   —   84,000
M.O. Hesse
 Chairman of the Board		   86,000   —   —   —   —   —   86,000
G.K. Petty   81,000   —   —   —   —   —   81,000
D.A. Westbrook   20,250   —   —   —   —   —   20,250

        The General Partner indemnifies each director for actions associated with being a director to the full extent permitted under Delaware law and maintains errors and omissions insurance.

120


COMPENSATION REPORT OF THE BOARD OF DIRECTORS

        The Board of Directors of Enbridge Energy Management, L.L.C., as delegate of the general partner of Enbridge Energy Partners, L.P., has reviewed and discussed the Compensation Discussion and Analysis section of this report with management and, based on that review and discussion, has recommended that the Compensation Discussion and Analysis be included in this report.

/s/  STEPHEN J.J. LETWIN      
Stephen J.J. Letwin
 Managing Director and Director		   /s/  T.L. MCGILL      
T.L. McGill
 President and Director

/s/  J.A. CONNELLY      
J.A. Connelly
 Director
 
/s/  M.O. HESSE      
M.O. Hesse
 Director

/s/  G.K. PETTY      
G.K. Petty
 Director
 
/s/  D.A. WESTBROOK      
D.A. Westbrook
 Director

121


Item 12. Security Ownership of Certain Beneficial Owners and Management

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

        The following table sets forth information as of February 20, 2008, with respect to persons known to us to be the beneficial owners of more than 5% of any class of the Partnership's units:

Name and Address of Beneficial Owner
   Title of Class
   Amount and
Nature of
Beneficial
Ownership
   Percent
Of Class
Enbridge Energy Management, L.L.C.
1100 Louisiana, Suite 3300
Houston, TX 77002		   i-units   13,815,388   100.0
Enbridge Energy Company, Inc.
1100 Louisiana, Suite 3300
Houston, TX 77002		   Class B common units
Class C units		   3,912,750
6,032,016		   100.0
32.8
CDP Infrastructures Fund G.P.
1000 place Jean-Paul-Riopelle
Montreal, Québec H2Z 2B3		   Class C units   11,072,473   60.1
Tortoise Energy Infrastructure Corporation
10801 Mastin Blvd., Suite 222
Overland Park, KS 66210		   Class C units   1,008,091   5.5

SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS

        The following table sets forth information as of February 20, 2008, with respect to each class of our units and the Listed Shares of Enbridge Management beneficially owned by the NEOs, directors and nominees for director of the General Partner and all executive officers, directors and nominees for director of the Partnership as a group:

 
   Enbridge Energy Partners, L.P.
   Enbridge Energy Management, L.L.C.
Name
   Title of Class
   Amount and
Nature of
Beneficial
Ownership(1)
   Percent
Of Class
   Title of Class
   Number of
Shares(1)
   Percent
Of Class
M.O. Hesse   Class A common units   —   —   Listed Shares   8,222.05   *
J.A. Connelly   Class A common units   7,000   *   Listed Shares   —   —
G.K. Petty   Class A common units   2,617   *   Listed Shares   1,036.14   *
D.A. Westbrook   Class A common units   5,500   *   Listed Shares   —   —
S.J.J. Letwin   Class A common units   15,000   *   Listed Shares   —   —
T.L. McGill   Class A common units   —   —   Listed Shares   1,461.28   *
S.J. Wuori   Class A common units   —   —   Listed Shares   —   *
R.L. Adams   Class A common units   —   —   Listed Shares   —   —
E.C. Kaitson   Class A common units   —   —   Listed Shares   —   —
D.V. Krenz   Class A common units   —   —   Listed Shares   —   —
J.A. Loiacono   Class A common units   —   —   Listed Shares   —   —
M.A. Maki   Class A common units   —   —   Listed Shares   —   —
A. Monaco   Class A common units   —   —   Listed Shares   —   —
S.J. Neyland   Class A common units   —   —   Listed Shares   —   —
K.C. Puckett   Class A common units   —   —   Listed Shares   —   —
J.N. Rose   Class A common units   —   —   Listed Shares   —   —
A.M. Schneider   Class A common units   —   —   Listed Shares   —   —
B.A. Stevenson   Class A common units   —   —   Listed Shares   —   —
L.A. Zupan   Class A common units   —   —   Listed Shares   —   —
       
 
     
 
All Officers, directors and nominees as a group 19 persons)   Class A common units   30,117   *   Listed Shares   10,719.47   *
       
 
     
 
*
Less than 1%.

(1)
Each beneficial owner has sole voting and investment power with respect to all the units or shares attributed to him/her.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

INTEREST OF THE GENERAL PARTNER IN THE PARTNERSHIP

        At December 31, 2007, our general partner had the following ownership interest in us:

 
   Quantity
   Effective
Ownership %
  
Direct ownership          
  Class B common units representing limited partner interest   3,912,750   4.2 %
  Class C units representing limited partner interest   5,920,109   6.4 %
  General Partner interest   —   2.0 %
Indirect ownership          
  Enbridge Management shares (Listed and Voting)   2,336,038   2.5 %
   
 
 
  Total effective ownership   12,168,897   15.1 %
   
 
 

INTEREST OF ENBRIDGE MANAGEMENT IN THE PARTNERSHIP

        At December 31, 2007, Enbridge Management owned 13,564,086 i-units, representing a 14.7% limited partner interest in us. The i-units are a separate class of our limited partner interests. All of our i-units are owned by Enbridge Management and are not publicly traded. Enbridge Management's limited liability company agreement provides that the number of all of its outstanding shares, including the voting shares owned by the General Partner, at all times will equal the number of i-units that it owns. Through the combined effect of the provisions in the Partnership Agreement and the provisions of Enbridge Management's limited liability company agreement, the number of outstanding Enbridge Management shares and the number of our i-units will at all times be equal.

CASH DISTRIBUTIONS

        As discussed in "Part II, Item 7", we make quarterly cash distributions of all of our available cash to our General Partner and the holders of our common units. The holders of our i-units and Class C units receive in-kind distributions under the Partnership Agreement. Our General Partner receives incremental incentive cash distributions on the portion of cash distributions that exceed certain target thresholds on a per unit basis as follows:

 
   Unitholders
   General Partner
  
Quarterly Cash Distributions per Unit:          
  Up to $0.59 per unit   98 % 2 %
  First Target—$0.59 per unit up to $0.70 per unit   85 % 15 %
  Second Target—$0.70 per unit up to $0.99 per unit   75 % 25 %
  Over Second Target—Cash distributions greater than $0.99 per unit   50 % 50 %

        During 2007, we paid cash and incentive distributions to our general partner for its general partner ownership interest of approximately $34.9 million and cash distributions of $14.5 million in connection with its ownership of the Class B common units. The cash distributions we make to our general partner for its general partner ownership interest exclude an amount equal to two percent of the i-unit and Class C unit distributions to maintain its two percent general partner interest.

IN-KIND DISTRIBUTIONS

        Enbridge Management, as owner of our i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution to the General Partner and the holders of our Class A and Class B

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common units, we issue additional i-units to Enbridge Management in an amount determined by dividing the cash amount distributed per limited partner unit by the average price of one of Enbridge Management's listed shares on the NYSE for the 10-trading day period immediately preceding the ex-dividend date for Enbridge Management's shares multiplied by the number of shares outstanding on the record date. In 2007, we distributed a total of 889,938 i-units to Enbridge Management and retained cash totaling approximately $48.4 million in connection with these in-kind distributions.

        Holders of our Class C units receive quarterly distributions of additional Class C units with a value equal to the quarterly cash distribution we pay to the holders of our Class A and Class B common units. We determine the additional Class C units we will issue by dividing the quarterly cash distribution per unit we pay on our Class A and Class B common units by the average market price of a Class A common unit as listed on the NYSE for the 10-trading day period immediately preceding the ex-dividend date for our Class A common units multiplied by the number of Class C units outstanding on the record date. In 2007, we distributed a total of 385,032 Class C units to our general partner in lieu of making cash distributions and retained cash totaling approximately $21.1 million in connection with these in-kind distributions.

GENERAL PARTNER CONTRIBUTIONS

        Pursuant to our partnership agreement, our general partner is at all times required to maintain its two percent general partner ownership interest in us. During 2007, in connection with our issuances and sales in April 2007 of approximately 5.9 million Class C units, and in May 2007 of 5.3 million Class A common units, our general partner contributed approximately $6.4 million and $6.1 million to us, respectively, to maintain its two percent general partner ownership interest.

OTHER RELATED PARTY TRANSACTIONS

        We do not directly employ any of the individuals responsible for managing or operating our business, nor do we have any directors. We obtain managerial, administrative and operational services from our general partner and affiliates of Enbridge pursuant to service agreements among us, Enbridge Management, and affiliates of Enbridge. Pursuant to these service agreements, we have agreed to reimburse our general partner and affiliates of Enbridge for the cost of managerial, administrative, operational and director services they provide to us.

Hungary Note Payable

        In December 2007, we repaid $145.0 million of a note payable to Enbridge Hungary Liquidity Management Ltd. (the "Hungary Note"), a wholly-owned subsidiary of Enbridge, including $8.8 million of accrued interest. We repaid the Hungary Note with proceeds we received from entering into a new note payable agreement with Hungary Liquidity Management Ltd. (the "new Hungary Note") on substantially the same terms, and approximately $15 million from our existing cash. The new Hungary Note bears interest at a fixed rate of 8.4% per annum that is payable semi-annually in June and December of each year through its maturity in December 2017. Similar to the old Hungary Note, the new note allows us the option of paying accrued and unpaid interest in the form of additional indebtedness by increasing the principal balance of the note for the amounts due. Consistent with the original Hungary Note, the new Hungary Note has cross-default provisions that are triggered by events of default under our First Mortgage Notes or defaults under our Credit Facility. The new Hungary Note is subordinate to our Credit Facility and other senior indebtedness, and ranks equally with current and future Junior Notes. We entered into the original Hungary Note agreement in connection with our acquisition of the Midcoast system in October 2002.

124

EUS Credit Agreement

        In December 2007, we entered into an unsecured revolving credit agreement (the "EUS Credit Agreement") with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge. The EUS Credit Agreement provides for a maximum principal amount of credit available to us at any one time of $500 million for a three-year term that matures in December 2010. The EUS Credit Agreement also includes financial covenants that are consistent with those in our Second Amended and Restated Credit Agreement. Amounts borrowed under the EUS Credit Agreement bear interest at rates that are consistent with the interest rates set forth in our Second Amended and Restated Credit Agreement. At December 31, 2007, we had no balances outstanding under the EUS Credit Agreement and the full amount remains available for our use.

Facilities Cost Reimbursement Agreement

        In 2007, we entered into an agreement with Enbridge Pipelines Inc., a wholly-owned subsidiary of Enbridge, to install and operate certain sampling and related facilities for the purpose of improving the quality of crude oil and the transportation services on our Lakehead system, which directly increases the transportation services revenue of Enbridge Pipelines Inc. As compensation for installing and operating these transportation facilities, Enbridge Pipelines Inc. makes annual payments to us on a cost of service basis. The income we accrued for providing these transportation services in 2007 was approximately $0.6 million.

        For further discussion of these and other related party transactions, refer to "Note 11—Related Party Transactions" in the consolidated financial statements beginning on Page F-2 of this Annual Report on Form 10-K.

REVIEW, APPROVAL OR RATIFICATION OF TRANSACTIONS WITH RELATED PERSONS

        If we contemplate entering into a transaction, other than a routine or in the ordinary course of business transaction, in which a related person will have a direct or indirect material interest, the proposed transaction is submitted for consideration to the board of directors of our general partner or Enbridge Management, as appropriate. The board of directors then determines whether it is advisable to constitute a special committee of independent directors to evaluate the proposed transaction. If a special committee is appointed, the committee obtains information regarding the proposed transaction from management and determines whether it is advisable to engage independent legal counsel or an independent financial advisor to advise the members of the committee regarding the transaction. If the special committee retains such counsel or financial advisor, it considers the advice and, in the case of a financial advisor, such advisor's opinion as to whether the transaction is fair to us and all of our unitholders.

        Potential transactions with related persons that are not financially significant so as to require review by the board of directors are disclosed to the President of Enbridge Management and our general partner and reviewed for compliance with the Enbridge Statement on Business Conduct. The President may also consult with legal counsel in making such determination. If a related person transaction occurred and was later found not to comply with the Statement on Business Conduct, the transaction would be reported to the board of directors for further review and ratification or remedial action.

        During 2007, we had the following "related person" transactions (as the term is defined in Item 404 of Regulation S-K):

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Item 14. Principal Accountant Fees and Services

        The following table sets forth the aggregate fees billed for professional services rendered by PricewaterhouseCoopers LLP, our principal independent auditors, for each of our last two fiscal years.

 
   For the years ended
December 31,
 
   2007
   2006
Audit fees(1)   $ 2,453,000   $ 2,405,200
Audit related fees     —     —
Tax fees(2)     702,500     625,000
All other fees     —     —
   
 
  Total   $ 3,155,500   $ 3,030,200
   
 
(1)
Audit fees consist of fees billed for professional services rendered for the audit of our consolidated financial statements, reviews of our interim consolidated financial statements, audits of various subsidiaries for statutory and regulatory filing requirements and our debt and equity offerings.

(2)
Tax fees consist of fees billed for professional services rendered for federal and state tax compliance for Partnership tax filings and unitholder K-1's.

        Engagements for services provided by PricewaterhouseCoopers LLP are subject to pre-approval by the Audit, Finance & Risk Committee of Enbridge Management's board of directors, or services up to $50,000 may be approved by the Chairman of the Audit, Finance & Risk Committee, under board of directors' delegated authority. All services in 2007 and 2006 were approved by the Audit, Finance & Risk Committee.

126


PART IV

Item 15. Exhibits, Financial Statement Schedules

        The following documents are filed as a part of this report:

        (1)   Financial Statements, which are incorporated by reference in Item 8 are included beginning on page F-1.

        (2)   Financial Statement Schedules.

        (3)   Exhibits.

127


SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
  
    
  ENBRIDGE ENERGY PARTNERS, L.P.
(Registrant)

 
By:
 
Enbridge Energy Management, L.L.C.,
as delegate of the General Partner

 
By:
 
/s/  STEPHEN J.J. LETWIN      
Stephen J.J. Letwin
Date: February 21, 2008     (Managing Director)

        Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on February 21, 2008 by the following persons on behalf of the Registrant and in the capacities indicated.

/s/  STEPHEN J.J. LETWIN      
Stephen J.J. Letwin		   /s/  M.A. MAKI      
M.A. Maki
Managing Director
(Principal Executive Officer)		   Vice President—Finance
(Principal Financial Officer)

/s/  T.L. MCGILL      
T.L. McGill
 
/s/  S.J. NEYLAND      
S.J. Neyland
President and Director   Controller

/s/  J.A. CONNELLY      
J.A. Connelly
 
/s/  M.O. HESSE      
M.O. Hesse
Director   Director

/s/  G.K. PETTY      
G.K. Petty
 
/s/  D.A. WESTBROOK      
D.A. Westbrook
Director   Director

128

Index of Exhibits

        Each exhibit identified below is filed as a part of this Annual report. Exhibits included in this filing are designated by an asterisk; all exhibits not so designated are incorporated by reference to a prior filing as indicated. Exhibits designated with a "+" constitute a management contract or compensatory plan arrangement required to be filed as an exhibit to this report pursuant to Item 15(c) of Form 10-K.

Exhibit
Number
   Description
3.1   Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.1 of the Partnership's Registration Statement No. 33-43425).
3.2   Certificate of Amendment to Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.2 of the Partnership's 2000 Form 10-K/A dated October 9, 2001).
3.3   Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated August 15, 2006 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K dated August 16, 2006).
3.4   First Amendment to the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, dated December 28, 2007 (incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K dated January 3, 2008).
4.1   Form of Certificate representing Class A Common Units (incorporated by reference to Exhibit 4.1 of the Partnership's 2000 Form 10-K/A dated October 9, 2001).
4.2   Registration Rights Agreement, dated August 15, 2006, between Enbridge Energy Partners, L.P. and CDP Infrastructures Fund G.P. (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K dated August 16, 2006).
4.3   Registration Rights Agreement, dated April 2, 2007, between Enbridge Energy Partners, L.P. and CDP Infrastructures Fund G.P., Tortoise Energy Infrastructure Corporation and Tortoise Energy Capital Corporation (incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K dated April 2, 2007).
10.1   Contribution, Conveyance and Assumption Agreement, dated December 27, 1991, among Lakehead Pipe Line Company, Inc., Lakehead Pipe Line Partners, L.P. and Lakehead Pipe Line Company, Limited Partnership. (incorporated by reference to Exhibit 10.10 of the Partnership's 1991 Form 10-K).
10.2   LPL Contribution and Assumption Agreement, dated December 27, 1991, among Lakehead Pipe Line Company, Inc., Lakehead Pipe Line Partners, L.P. and Lakehead Pipe Line Company, Limited Partnership and Lakehead Services, Limited Partnership. (incorporated by reference to Exhibit 10.11 of the Partnership's 1991 Form 10-K).
10.3   Contribution Agreement (incorporated by reference to Exhibit 10.1 of the Partnership's Registration Statement on Form S-3/A filed on July 8, 2002).
10.4   First Amendment to Contribution Agreement (incorporated by reference to Exhibit 10.8 of the Partnership's Registration Statement on Form S-3/A filed on September 24, 2002).
10.5   Second Amendment to Contribution Agreement (incorporated by reference to Exhibit 99.3 of the Partnership's Current Report on Form 8-K filed on October 31, 2002).
10.6   Delegation of Control Agreement (incorporated by reference to Exhibit 10.2 of the Partnership's Quarterly Report on Form 10-Q filed on November 14, 2002).
10.7   First Amending Agreement to the Delegation of Control Agreement dated as of February 21, 2005 (incorporated by reference to Exhibit 10.1 of the Partnership's Quarterly Report on Form 10-Q filed on May 5, 2005).
10.8   Amended and Restated Treasury Services Agreement (incorporated by reference to Exhibit 10.3 of the Partnership's Quarterly Report on Form 10-Q filed on November 14, 2002).

129

10.9   Operational Services Agreement (incorporated by reference to Exhibit 10.4 of the Partnership's Quarterly Report on Form 10-Q filed on November 14, 2002).
10.10   General and Administrative Services Agreement (incorporated by reference to Exhibit 10.5 of the Partnership's Quarterly Report on Form 10-Q filed on November 14, 2002).
10.11   Omnibus Agreement (incorporated by reference to Exhibit 10.6 of the Partnership's Quarterly Report on Form 10-Q filed on November 14, 2002).
10.12   Second Amended and Restated Credit Agreement, dated April 4, 2007, among Enbridge Energy Partners, L.P., Bank of America, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K dated April 10, 2007).
10.13   Commercial Paper Dealer Agreement between the Company, as Issuer, and Banc of America Securities LLC, as Dealer, dated as of April 21, 2005 (incorporated by reference to Exhibit 10.1 of the Partnership's Current Report on Form 8-K filed May 3, 2005).
10.14   Commercial Paper Dealer Agreement between the Company, as Issuer, and Deutsche Bank Securities Inc., as Dealer, dated as of April 21, 2005 (incorporated by reference to Exhibit 10.2 of the Partnership's Current Report on Form 8-K filed May 3, 2005).
10.15   Commercial Paper Dealer Agreement between the Company, as Issuer, and Goldman, Sachs & Co., as Dealer, dated as of April 21, 2005 (incorporated by reference to Exhibit 10.3 of the Partnership's Current Report on Form 8-K filed May 3, 2005).
10.16   Commercial Paper Dealer Agreement between the Company, as Issuer, and Merrill Lynch Money Markets Inc., as Dealer, dated as of April 21, 2005 (incorporated by reference to Exhibit 10.4 of the Partnership's Current Report on Form 8-K filed May 3, 2005).
10.17   Issuing and Paying Agency Agreement between the Company and Deutsche Bank Trust Company Americas, dated as of April 21, 2005 (incorporated by reference to Exhibit 10.5 of the Partnership's Current Report on Form 8-K filed May 3, 2005).
10.18   Note Agreement and Mortgage, dated December 12, 1991 (incorporated by reference to Exhibit 10.1 of the Partnership's 1991 Form 10-K).
10.19   Assumption and Indemnity Agreement, dated December 18, 1992, between Interprovincial Pipe Line Inc. and Interprovincial Pipe Line System Inc. (incorporated by reference to Exhibit 10.4 of the Partnership's 1992 Form 10-K).
10.20   Settlement Agreement, dated August 28, 1996, between Lakehead Pipe Line Company, Limited Partnership and the Canadian Association of Petroleum Producers and the Alberta Department of Energy (incorporated by reference to Exhibit 10.17 of the Partnership's 1996 Form 10-K).
10.21   Tariff Agreement as filed with the Federal Energy Regulatory Commission for the System Expansion Program II and Terrace Expansion Project (incorporated by reference to Exhibit 10.21 of the Partnership's 1998 Form 10-K).
10.22   Offer of Settlement dated December 31, 2005, as filed with the Federal Energy Regulatory Commission for approval to implement an additional component of the Facilities Surcharge to permit recovery by Enbridge Energy, Limited Partnership of the costs for the Southern Access Mainline Expansion and approval of the Offer of Settlement dated March 16, 2006 (incorporated by reference to Exhibit 10.3 of the Partnership's Quarterly Report on Form 10-Q filed July 30, 2007).
10.23   Promissory Note, dated as of September 30, 1998, given by Lakehead Pipe Line Company, Limited Partnership, as borrower, to Lakehead Pipe Line Company, Inc., as lender (incorporated by reference to Exhibit 10.19 of the Partnership's 1998 Form 10-K).
10.24   Promissory Note, dated as of March 31, 1999, given by Lakehead Pipe Line Company, Limited Partnership, as borrower, to Lakehead Pipe Line Company, Inc., as lender. (incorporated by reference to Exhibit 10.26 of the Partnership's 1999 Form 10-K).

130

10.25   Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (incorporated by reference to Exhibit 4.1 of the Lakehead Pipe Line Company, Limited Partnership's Current Report on Form 8-K dated October 20, 1998).
10.26   First Supplemental Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (incorporated by reference to Exhibit 4.2 of the Lakehead Pipe Line Company, Limited Partnership's Current Report on Form 8-K dated October 20, 1998).
10.27   Second Supplemental Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (incorporated by reference to Exhibit 4.3 of the Lakehead Pipe Line Company, Limited Partnership's Current Report on Form 8-K dated October 20, 1998).
10.28   Third Supplemental Indenture dated November 21, 2000, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (incorporated by reference to Exhibit 4.2 of the Lakehead Pipe Line Company, Limited Partnership's Current Report on Form 8-K dated November 16, 2000).
10.29   Indenture dated September 15, 1998, between Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank (incorporated by reference to Exhibit 4.4 of the Lakehead Pipe Line Company, Limited Partnership's Current Report on Form 8-K dated October 20, 1998).
10.30+   Executive Employment Agreement, dated April 14, 2003, between Stephen J.J. Letwin, as Executive, and Enbridge Inc., as Corporation (incorporated by reference to Exhibit 10.1 of the Partnership's Current Report on Form 8-K filed on May 3, 2006).
10.31+   Executive Employment agreement between Stephen J. Wuori and Enbridge Inc. dated April 14, 2003 (incorporated by reference to our Current Report on Form 8-K dated January 28, 2008).
10.32+   Executive Employment Agreement, dated May 11, 2001, between E. Chris Kaitson, as Executive, and Enbridge Inc., as Corporation (incorporated by reference to Exhibit 10.27 of the Partnership's Annual Report on Form 10-K filed on March 28, 2003).
10.33   Indenture dated May 27, 2003, between the Partnership, as Issuer, and SunTrust Bank, as Trustee (incorporated by reference to Exhibit 4.5 of the Partnership's Registration Statement on Form S-4 filed on June 30, 2003).
10.34   First Supplemental Indenture dated May 27, 2003 between the Partnership and SunTrust Bank (incorporated by reference to Exhibit 4.5 of the Partnership's Registration Statement on Form S-4 filed on June 30, 2003).
10.35   Second Supplemental Indenture dated May 27, 2003 between the Partnership and SunTrust Bank (incorporated by reference to Exhibit 4.5 of the Partnership's Registration Statement on Form S-4 filed on June 30, 2003).
10.36   Third Supplemental Indenture dated January 9, 2004 between the Partnership and SunTrust Bank (incorporated by reference to Exhibit 99.3 of the Partnership's Current Report on Form 8-K filed on January 9, 2004).
10.37   Fourth Supplemental Indenture dated December 3, 2004 between the Partnership and SunTrust Bank (incorporated by reference to Exhibit 4.2 of the Partnership's Current Report on Form 8-K filed on December 3, 2004).
10.38   Fifth Supplemental Indenture dated December 3, 2004 between the Partnership and SunTrust Bank (incorporated by reference to Exhibit 4.3 of the Partnership's Current Report on Form 8-K filed on December 3, 2004).

131

10.39   Sixth Supplemental Indenture dated December 21, 2006 between the Partnership and U.S. Bank National Association, successor to SunTrust Bank, as trustee (incorporated by reference to Exhibit 4.2 of the Partnership's Current Report on Form 8-K filed on December 21, 2006).
10.40   Indenture for Subordinated Debt Securities dated as of September 27, 2007 between Enbridge Energy Partners, L.P. and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of the Partnership's Current Report on Form 8-K dated September 28, 2007).
10.41   First Supplemental Indenture to the Indenture dated as of September 27, 2007 between Enbridge Energy Partners, L.P. and U.S. Bank National Association, as Trustee (including form of Note) (incorporated by reference to Exhibit 4.2 of the Partnership's Current Report on Form 8-K dated September 28, 2007).
10.42   Replacement Capital Covenant dated as of September 27, 2007 by Enbridge Energy Partners, L.P. in favor of the debtholders designated therein (incorporated by reference to Exhibit 10.1 of the Partnership's Current Report on Form 8-K dated September 28, 2007).
10.43   Common Unit Purchase Agreement (incorporated by reference to Exhibit 1.1 of the Partnership's Current Report on Form 8-K filed on February 10, 2005).
14.1   Code of Ethics for Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Partnership's Annual Report on Form 10-K filed on March 12, 2004).
21.1*   Subsidiaries of the Registrant.
23.1*   Consent of PricewaterhouseCoopers LLP.
31.1*   Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*   Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*   Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*   Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1   Charter of the Audit, Finance & Risk Committee of Enbridge Energy Management, L.L.C. (incorporated by reference to Exhibit 99.1 of the Partnership's Annual Report on Form 10-K filed February 25, 2005).

        Copies of Exhibits may be obtained upon written request of any Unitholder to Investor Relations, Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300, Houston, Texas 77002.

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS,
SUPPLEMENTARY INFORMATION AND
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

ENBRIDGE ENERGY PARTNERS, L.P.

 
   Page
Financial Statements    
Report of Independent Registered Public Accounting Firm   F-2
Consolidated Statements of Income for each of the years ended December 31, 2007, 2006 and 2005   F-3
Consolidated Statements of Comprehensive Income for each of the years ended December 31, 2007, 2006 and 2005   F-4
Consolidated Statements of Cash Flows for each of the years ended December 31, 2007, 2006 and 2005   F-5
Consolidated Statements of Financial Position as of December 31, 2007 and 2006   F-6
Consolidated Statements of Partners' Capital for each of the years ended December 31, 2007, 2006 and 2005   F-7
Notes to the Consolidated Financial Statements   F-8

FINANCIAL STATEMENT SCHEDULES

        Financial statement schedules not included in this report have been omitted because they are not applicable or the required information is either immaterial or shown in the consolidated financial statements or notes thereto.

F-1


Report of Independent Registered Public Accounting Firm

To the Partners of
Enbridge Energy Partners, L.P.:

        In our opinion, the accompanying consolidated statements of financial position and the related consolidated statements of income and comprehensive income, of partners capital and of cash flows present fairly, in all material respects, the financial position of Enbridge Energy Partners, L.P. and its subsidiaries (the "Partnership") at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

        A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Houston, Texas
February 21, 2008

F-2


ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

 
   Year ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in millions, except per unit amounts)

  
Operating revenue   $ 7,282.6   $ 6,509.0   $ 6,476.9  
   
 
 
 
Operating expenses                    
  Cost of natural gas (Note 5 and 14)     6,246.9     5,514.6     5,763.3  
  Operating and administrative     434.3     364.8     326.8  
  Power     117.0     107.6     74.8  
  Depreciation and amortization (Note 6)     165.6     135.1     138.2  
Gain on sale of assets (Note 3)     —     —     (18.1 )
   
 
 
 
      6,963.8     6,122.1     6,285.0  
   
 
 
 
Operating income     318.8     386.9     191.9  
Interest expense     99.8     110.5     107.7  
Other income     3.0     8.5     5.0  
   
 
 
 
Income from continuing operations before income tax expense     222.0     284.9     89.2  
Income tax expense (Note 15)     5.1     —     —  
   
 
 
 
Income from continuing operations     216.9     284.9     89.2  
Income from discontinued operations (Note 3)     32.6     —     —  
   
 
 
 
Net income   $ 249.5   $ 284.9   $ 89.2  
   
 
 
 
Net income allocable to limited partner units (Note 4)                    
  Income from continuing operations   $ 179.9   $ 254.0   $ 65.7  
  Income from discontinued operations     31.9     —     —  
   
 
 
 
    Net income allocable to limited partner units   $ 211.8   $ 254.0   $ 65.7  
   
 
 
 
Basic and diluted earnings per limited partner unit (Note 4)                    
  Income from continuing operations   $ 2.08   $ 3.62   $ 1.06  
  Income from discontinued operations     0.37     —     —  
   
 
 
 
    Net income per limited partner unit (basic and diluted)   $ 2.45   $ 3.62   $ 1.06  
   
 
 
 
Weighted average limited partner units outstanding     86.3     70.2     62.1  
   
 
 
 
Cash distributions paid per limited partner unit   $ 3.725   $ 3.700   $ 3.700  
   
 
 
 

The accompanying notes are an integral part of these consolidated financial statements.

F-3


ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
   Year ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in millions)

  
Net income   $ 249.5   $ 284.9   $ 89.2  
Other comprehensive income (loss) net of tax benefit of $1.6, $0.9, and $0, respectively (Note 14)     (104.8 )   112.5     (181.3 )
   
 
 
 
Comprehensive income (loss)   $ 144.7   $ 397.4   $ (92.1 )
   
 
 
 

The accompanying notes are an integral part of these consolidated financial statements.

F-4


ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 
   Year ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in millions)

  
Cash provided by operating activities                    
  Net income   $ 249.5   $ 284.9   $ 89.2  
  Adjustments to reconcile net income to net cash provided by operating activities:                    
    Depreciation and amortization (Note 6)     165.6     135.1     138.2  
    Derivative fair value losses (gains) (Notes 13 and 14)     64.2     (64.4 )   58.4  
    Gain on sale of net assets (Note 3)     (32.6 )   —     (18.1 )
    Inventory market price adjustments (Note 5)     4.5     17.7     —  
    Other     1.8     8.3     (0.8 )
    Changes in operating assets and liabilities, net of acquisitions:                    
      Receivables, trade and other     (11.1 )   (37.0 )   (38.0 )
      Due from General Partner and affiliates (Note 11)     3.3     (10.4 )   (12.4 )
      Accrued receivables     (82.3 )   98.8     (237.1 )
      Inventory (Note 5)     2.0     1.1     (57.5 )
      Current and long-term other assets (Notes 13 and 14)     (3.9 )   (2.7 )   (2.2 )
      Due to General Partner and affiliates (Note 11)     23.2     10.1     2.6  
      Accounts payable and other (Notes 2, 13 and 14)     (3.1 )   4.3     42.2  
      Accrued purchases     73.5     (116.4 )   295.3  
      Interest payable     9.5     4.4     8.8  
      Current income tax payable (Note 15)     4.9     —     —  
      Property and other taxes payable     (4.7 )   (2.0 )   (1.5 )
  Settlement of interest rate derivatives (Note 14)     (0.9 )   (10.2 )   —  
   
 
 
 
Net cash provided by operating activities     463.4     321.6     267.1  
   
 
 
 
Cash used in investing activities                    
    Additions to property, plant and equipment     (1,980.2 )   (864.4 )   (344.8 )
    Changes in construction payables     83.6     30.4     2.8  
    Asset acquisitions, net of cash acquired (Note 3)     —     (33.3 )   (186.4 )
    Proceeds from sale of net assets (Note 3)     133.0     0.2     105.4  
    Settlement of natural gas collars (Note 3 and 14)     —     —     (16.3 )
    Other     (1.4 )   0.1     2.2  
   
 
 
 
Net cash used in investing activities     (1,765.0 )   (867.0 )   (437.1 )
   
 
 
 
Cash provided by financing activities                    
    Net Proceeds from unit issuances (Note 10)     628.8     509.6     268.6  
    Distributions to partners (Note 10)     (245.4 )   (227.4 )   (210.6 )
    Net proceeds from issuances of long term debt (Note 9)     592.8     297.6     —  
    Net Credit Facility borrowings (repayments) (Note 9)     400.0     —     (175.0 )
    Net commercial paper issuances (repayments) (Note 9)     (171.5 )   111.4     330.0  
    Affiliate note borrowings (Note 11)     130.0     —     —  
    Affiliate note repayments (Note 11)     (136.2 )   (20.0 )   —  
    Repayments of First Mortgage Notes (Note 9)     (31.0 )   (31.0 )   (31.0 )
    Other     —     —     (0.5 )
   
 
 
 
Net cash provided by financing activities     1,167.5     640.2     181.5  
   
 
 
 
Net increase (decrease) in cash and cash equivalents     (134.1 )   94.8     11.5  
Cash and cash equivalents at beginning of year     184.6     89.8     78.3  
   
 
 
 
Cash and cash equivalents at end of year   $ 50.5   $ 184.6   $ 89.8  
   
 
 
 

The accompanying notes are an integral part of these consolidated financial statements.

F-5


ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 
   December 31,
  
 
   2007
   2006
  
 
   (dollars in millions)

  
ASSETS              
Current assets              
  Cash and cash equivalents (Note 2)   $ 50.5   $ 184.6  
  Receivables, trade and other, net of allowance for doubtful accounts of $1.9 in 2007 and $2.4 in 2006     157.8     146.7  
  Due from General Partner and affiliates (Note 11)     27.2     30.5  
  Accrued receivables     598.8     516.5  
  Inventory (Note 5)     110.6     117.1  
  Other current assets (Notes 13 and 14)     14.8     13.9  
   
 
 
      959.7     1,009.3  
Property, plant and equipment, net (Note 6)     5,554.9     3,824.9  
Goodwill (Note 7)     256.5     265.7  
Intangibles, net (Note 8)     91.5     97.8  
Other assets, net (Notes 13, 14 and 15)     29.0     26.1  
   
 
 
    $ 6,891.6   $ 5,223.8  
   
 
 
LIABILITIES AND PARTNERS' CAPITAL              
Current liabilities              
  Due to General Partner and affiliates (Note 11)   $ 45.8   $ 22.6  
  Accounts payable and other (Notes 13 and 14)     400.4     211.5  
  Accrued purchases     603.8     530.3  
  Interest payable     20.9     11.4  
  Property and other taxes payable (Note 15)     22.5     18.6  
  Notes payable to affiliate (Note 11)     —     136.2  
  Current maturities of long-term debt (Note 9)     31.0     31.0  
   
 
 
      1,124.4     961.6  
Long-term debt (Note 9)     2,862.9     2,066.1  
Environmental liabilities (Note 12)     2.8     3.3  
Notes payable to affiliate (Note 11)     130.0     —  
Other long-term liabilities (Notes 13 and 14)     200.0     149.4  
   
 
 
      4,320.1     3,180.4  
   
 
 
Commitments and contingencies (Note 12)              

Partners' capital (Note 10)
 
 
 
 
 
 
 
  Class A common units (55,238,834 and 49,938,834 at December 31, 2007 and 2006, respectively)     1,340.7     1,141.7  
  Class B common units (3,912,750 at December 31, 2007 and 2006)     72.9     67.6  
  Class C units (18,073,367 and 11,070,152 at December 31, 2007 and 2006, respectively)     874.1     509.8  
  i-units (13,564,086 and 12,674,148 at December 31, 2007 and 2006, respectively)     515.3     466.3  
  General Partner     62.9     47.6  
  Accumulated other comprehensive loss (Notes 13 and 14)     (294.4 )   (189.6 )
   
 
 
      2,571.5     2,043.4  
   
 
 
    $ 6,891.6   $ 5,223.8  
   
 
 

        The accompanying notes are an integral part of these consolidated financial statements.

F-6


ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

 
   Year ended December 31,
  
 
   2007
   2006
   2005
  
 
   Units
   Amount
   Units
   Amount
   Units
   Amount
  
 
   (in millions, except unit amounts)

  
Class A common units:                                
  Beginning balance   49,938,834   $ 1,141.7   49,938,834   $ 1,142.4   44,296,134   $ 1,021.6  
  Net income allocation   —     130.1   —     184.1   —     48.9  
  Allocation of proceeds and issuance costs from unit issuance   5,300,000     264.9   —     —   5,642,700     242.7  
  Distributions   —     (196.0 ) —     (184.8 ) —     (170.8 )
   
 
 
 
 
 
 
  Ending balance   55,238,834     1,340.7   49,938,834     1,141.7   49,938,834     1,142.4  
   
 
 
 
 
 
 
Class B common units:                                
  Beginning balance   3,912,750     67.6   3,912,750     67.2   3,912,750     66.7  
  Net income allocation   —     9.8   —     14.9   —     4.8  
  Allocation of proceeds and issuance costs from unit issuance   —     10.0   —     —   —     10.2  
  Distributions   —     (14.5 ) —     (14.5 ) —     (14.5 )
   
 
 
 
 
 
 
  Ending balance   3,912,750     72.9   3,912,750     67.6   3,912,750     67.2  
   
 
 
 
 
 
 
Class C units:                                
  Beginning balance   11,070,152     509.8   —     —   —     —  
  Net income allocation   —     39.9   —     10.4   —     —  
  Allocation of proceeds and issuance costs from unit issuance   5,930,792     324.4   10,869,565     499.4   —     —  
  Distributions   1,072,423     —   200,587     —   —     —  
   
 
 
 
 
 
 
  Ending balance   18,073,367     874.1   11,070,152     509.8   —     —  
   
 
 
 
 
 
 
i-units:                                
  Beginning balance   12,674,148     466.3   11,704,948     421.7   10,902,409     399.4  
  Net income allocation   —     32.0   —     44.6   —     12.0  
  Allocation of proceeds and issuance costs from unit issuance   —     17.0   —     —   —     10.3  
  Distributions   889,938     —   969,200     —   802,539     —  
   
 
 
 
 
 
 
  Ending balance   13,564,086     515.3   12,674,148     466.3   11,704,948     421.7  
   
 
 
 
 
 
 
General Partner:                                
  Beginning balance         47.6         34.6         31.0  
  Net income allocation         37.7         30.9         23.5  
  Allocation of proceeds and issuance costs from unit issuance         —         —         (0.3 )
  General Partner contribution         12.5         10.2         5.7  
  Distributions         (34.9 )       (28.1 )       (25.3 )
       
     
     
 
  Ending balance         62.9         47.6         34.6  
       
     
     
 
Accumulated other comprehensive loss:                                
  Beginning balance         (189.6 )       (302.1 )       (120.8 )
  Net realized losses on changes in fair value of derivative financial instruments reclassified to earnings         94.8         78.3         33.8  
  Unrealized gain (loss) on derivative financial instruments         (199.6 )       34.2         (215.1 )
       
     
     
 
  Ending balance         (294.4 )       (189.6 )       (302.1 )
       
     
     
 
  Partners' capital at December 31,       $ 2,571.5       $ 2,043.4       $ 1,363.8  
       
     
     
 

The accompanying notes are an integral part of these consolidated financial statements.

F-7


ENBRIDGE ENERGY PARTNERS, L.P.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS

General

        Enbridge Energy Partners, L.P. and its consolidated subsidiaries, referred to herein as "we," "us," "our," and the "Partnership," is 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, transmission and marketing assets in the United States of America. Our Class A common units are traded on the New York Stock Exchange ("NYSE") under the symbol "EEP."

        We were formed in 1991 by Enbridge Energy Company, Inc. (the "General Partner"), which is an indirect, wholly-owned subsidiary of Enbridge Inc. ("Enbridge") of Calgary, Alberta. We were formed to acquire, own and operate the crude oil and liquid petroleum transportation assets of Enbridge Energy, Limited Partnership (the "OLP") which owns 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.

        We are a geographically and operationally diversified organization, providing crude oil gathering, transportation and storage services, and natural gas gathering, treating, processing, marketing and transportation services in the Gulf Coast and Mid-continent regions of the United States. We hold our assets in a series of limited liability companies and limited partnerships that we own directly or indirectly.

        Our ownership includes general partner interests and limited partner interests. Our limited partner interests consist of Class A and Class B common units, Class C units and i-units, which we collectively refer to as the limited partner units. At December 31, 2007 and 2006, our ownership is distributed as follows:

 
   2007
   2006
  
Class A common units owned by the public   59.6 % 63.1 %
Class B common units owned by our General Partner   4.2 % 4.9 %
Class C units owned by our General Partner   6.4 % 7.0 %
Class C units owned by institutional investors   13.1 % 7.0 %
i-units owned by Enbridge Management   14.7 % 16.0 %
General Partner interest   2.0 % 2.0 %
   
 
 
    100.0 % 100.0 %
   
 
 

Enbridge Energy Management, L.L.C.

        Enbridge Energy Management, L.L.C. and its subsidiary, which we refer to as Enbridge Management, is a Delaware limited liability company that was formed in May 2002. Our general partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management. Enbridge Management's Listed Shares are traded on the NYSE under the symbol "EEQ." Enbridge Management owns all of a special class of our limited partner interests, referred to as "i-units" and receives its earnings from this investment.

        Enbridge Management's principal activity is managing and controlling our business and affairs pursuant to a delegation of control agreement with our general partner. The delegation of control agreement provides that Enbridge Management will not amend or propose to amend our partnership agreement, allow a merger or consolidation involving us, allow a sale or exchange of all or substantially all of our assets or dissolve or liquidate us without the approval of our general partner. In accordance with its

F-8


limited liability company agreement, Enbridge Management's activities are restricted to being our limited partner and managing our business and affairs.

Enbridge Inc.

        Enbridge is the indirect parent of our general partner and is publicly traded on the NYSE and Toronto Stock Exchange under the symbol "ENB." Enbridge is a leader in the transportation and distribution of energy, with a focus on crude oil and liquids pipelines, natural gas pipelines and natural gas distribution in North America. Enbridge also has international interests located in Western Europe and Latin America. At December 31, 2007 and 2006, Enbridge and its consolidated subsidiaries owned an effective 15.1% and 16.7% interest in us through its ownership in Enbridge Management and our general partner.

Business Segments

        We conduct our business through three segments: Liquids, Natural Gas, and Marketing.

        Our Liquids segment includes the Lakehead, North Dakota, and the Mid-Continent systems. Our Lakehead system consists of an interstate common carrier crude oil and liquid petroleum pipeline that is regulated by the Federal Energy Regulatory Commission, or FERC, and storage assets, all of which are located in the Great Lakes and Midwest regions of the United States. Our Lakehead system, together with the Enbridge system in Canada owned by Enbridge, forms the longest liquid petroleum pipeline in the world. The Lakehead system, which spans approximately 3,300 miles, has been in operation for over 50 years and is the primary transporter of crude oil and liquid petroleum from western Canada to the United States. The Lakehead system serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the province of Ontario, Canada. Our North Dakota system includes approximately 330 miles of crude oil gathering lines connected to an interstate transportation line that is approximately 620 miles long and is regulated by the FERC. The North Dakota system connects directly into the Lakehead system in the state of Minnesota. Our Mid-Continent system consists of over 480 miles of active crude oil pipelines, including the FERC-regulated Ozark pipeline and approximately 16.7 million barrels of storage capacity, which serve refineries in the U.S. Mid-continent region from Cushing, Oklahoma.

        Our Natural Gas segment consists of natural gas gathering and transmission pipelines, treating and processing plants and related facilities predominantly located in active producing basins in east and north Texas, as well as the Texas panhandle and western Oklahoma. Our Natural Gas segment includes ten natural gas treating plants and 24 natural gas processing plants at December 31, 2007, excluding plants that are inactive or under construction. In addition, our Natural Gas segment includes approximately 11,500 miles of natural gas gathering and transmission pipelines, as well as trucks, trailers and rail cars used for transporting natural gas liquids ("NGL" or "NGLs"), crude oil and carbon dioxide.

        Our Natural Gas segment also includes three FERC-regulated natural gas transmission pipeline systems located in the Southeast and Gulf Coast regions of the United States.

        Our Marketing segment primarily provides natural gas supply, transportation, balancing, storage and sales services for producers and wholesale customers on our natural gas pipelines as well as other interconnected natural gas pipeline systems. We primarily undertake marketing activities to increase the utilization of our natural gas pipelines, realize incremental income on gas purchased at the wellhead, and provide value-added services to customers.

F-9

        Our Marketing business purchases third-party pipeline transportation capacity which provides us and our customers with access to natural gas markets that might not be directly accessible from our existing natural gas pipelines. Our Marketing business also purchases third-party storage capacity which permits us to inject and store natural gas over various periods of time for withdrawal as these products become needed by end users of natural gas. These contracts may be denoted as firm transportation, interruptible transportation, firm storage, interruptible storage, or parking and lending services. These various contract structures are used to mitigate risk associated with our natural gas purchase and sale contracts and to provide us with opportunities to competitively market natural gas and NGL products.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Use of Estimates

        We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingent assets and liabilities. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known.

Principles of Consolidation

        The consolidated financial statements include the accounts of the Partnership and its wholly-owned subsidiaries on a consolidated basis. All significant intercompany accounts and transactions have been eliminated in consolidation.

Comparative Amounts

        We have made a reclassification to the prior years' reported amounts to conform to our presentation in the 2007 consolidated statements of financial position between other assets, net and intangibles, net. We reclassified $6.4 million from other assets, net to intangibles, net in our December 31, 2006 consolidated statement of financial position related to rights we received for contributions we made in aid of construction projects, consistent with our current period presentation.

Accounting for Regulated Operations

        Certain of our liquids and natural gas activities are subject to regulation by the FERC and various state authorities. Regulatory bodies exercise statutory authority over matters such as construction, rates and underlying accounting practices, and ratemaking agreements with customers.

        Certain of our natural gas systems are subject to the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, Accounting for the Effects of Certain Types of Regulation. Accordingly, we record certain assets and liabilities that result from the regulated ratemaking process that would not be recorded for non-regulated entities under U.S. GAAP.

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

Liquids

        Revenues of our Liquids segment are primarily derived from two sources, interstate transportation of crude oil and liquid petroleum under tariffs regulated by the FERC and contract storage revenues related to our crude oil storage assets. The tariffs established for our interstate pipelines specify the amounts to be paid by shippers for service between receipt and delivery locations and the general terms and conditions of

F-10


transportation services on the respective pipeline systems. We recognize revenue upon delivery of products to our customers, when pricing is determinable and collectibility is reasonably assured. We recognize contract storage revenues based on contractual terms under which customers pay for the option to use available storage capacity and/or a fee based on throughput volumes. We recognize revenues as storage services are rendered, pricing is determinable and collectibility is reasonably assured. In the Liquids segment, we generally do not own the crude oil and liquid petroleum that we transport or store, and therefore, we do not assume significant direct commodity price risk.

Natural Gas

        We recognize revenue upon delivery of natural gas and NGLs to customers, when services are rendered, pricing is determinable and collectibility is reasonably assured. We derive revenue in our Natural Gas segment from the following types of arrangements:

Fee-Based 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 provided and do not depend directly on commodity prices. Revenues of the Natural Gas segment that are derived from transmission services consist of reservation fees charged for transmission of natural gas on the FERC-regulated interstate natural gas transmission pipeline systems, while revenues from intrastate pipelines are generally derived from the bundled sales of natural gas and transmission services. Customers of the FERC-regulated natural gas pipeline systems typically pay a reservation fee each month to reserve capacity plus a nominal commodity charge based on actual transmission volumes.

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 and by the use of derivative financial instruments to hedge open positions. We will continue to hedge a significant amount of our commodity price risk to support the stability of our cash flows. Refer to Note 14 for more information about the derivative activities we use to mitigate this commodity price risk.

        These other types of arrangements are categorized as follows:

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        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. In order to protect our unitholders from volatility in our cash flows that can result from fluctuations in commodity prices, we enter into derivative financial instruments to effectively fix the sales price of the natural gas and NGLs we anticipate receiving under the terms of these contracts. As a result of entering into these derivative financial instruments, we have largely fixed the amount of cash that we will receive in the future when we sell the processed natural gas and NGLs, although the market price of these commodities will continue to fluctuate during that time.

Marketing

        Revenues of our Marketing segment are derived from providing supply, transportation, balancing, storage and sales services for producers and wholesale customers on our natural gas pipelines, as well as other interconnected pipeline systems. Natural gas marketing activities are primarily undertaken to realize incremental revenues on natural gas purchased at the wellhead, and to provide other services valued by our customers. In general, natural gas purchased and sold by our Marketing business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Higher premiums and associated revenues result from transactions that involve smaller volumes or that offer greater service flexibility for wholesale customers. At the request of some customers, we will enter into long-term fixed price purchase or sales contracts with our customers and usually will enter into offsetting positions under the same or similar terms. We recognize revenues upon delivery of natural gas and NGLs to our customers, when services are rendered, pricing is determinable and collectibility is reasonably assured.

Estimation of Revenue and Cost of Natural Gas

        For our natural gas and marketing businesses, we must estimate our current month revenue and cost of gas to permit the timely preparation of our consolidated financial statements. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data prior to preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues and cost of natural gas based on the best available volume and price data for natural gas delivered and received, along with a true-up of the prior month's estimate to equal the prior month's actual data. As a result, there is one month of estimated data recorded in our operating revenues and cost of natural gas for each of the years ended December 31, 2007, 2006 and 2005. We believe that the assumptions underlying these estimates will not be significantly different from actual amounts due to the routine nature of these estimates and the stability of our processes.

Cash and Cash Equivalents

        Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.

        We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have issued check payments that have not yet been presented to the financial institution of approximately $38.5 million at December 31, 2007 and $46.9 million at December 31, 2006 are included in Accounts payable and other on our Consolidated Statements of Financial Position.

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Allowance for Doubtful Accounts

        We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.

Inventory

        Inventory includes product inventory and materials and supplies inventory. We record all product inventories at the lower of our cost as determined on a weighted average basis, or market. The product inventory consists of liquids and natural gas. Upon disposition, product inventory is recorded to Cost of natural gas at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.

        Materials and supplies inventory is either used during operations and charged to operating expense as incurred, or used for capital projects and new construction, and capitalized to property, plant and equipment.

Oil Measurement Adjustments

        Oil measurement adjustments occur as part of the normal operating conditions associated with our Liquids pipelines. The three types of oil measurement adjustments include:

        Difficulties are inherent in quantifying oil measurement adjustments because physical measurements of volumes are not practical, as products continuously move through our pipelines and virtually all of these pipelines are located underground. Quantifying oil measurement adjustments is especially difficult for us because of the length of the pipeline systems and the number of different grades of crude oil and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined.

Operational Balancing Agreements and Natural Gas Imbalances

        To facilitate deliveries of natural gas and provide for operational flexibility, we have operational balancing agreements in place with other interconnecting pipelines. These agreements ensure that the volume of gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes the shipper previously scheduled, a gas imbalance is created. The imbalances are settled through periodic cash payments or repaid in kind through the receipt or delivery of natural gas in the future. Gas imbalances are recorded as accrued receivables and accrued purchases on our consolidated statements of financial position using the posted index prices, which approximate market rates, or our weighted average cost of gas.

Capitalization Policies, Depreciation Methods and Impairment of Property, Plant and Equipment

        We capitalize expenditures related to property, plant and equipment, subject to a minimum rule, that have a useful life greater than one year for (1) assets purchased or constructed; (2) existing assets that are

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replaced, improved, or the useful lives have been extended; or (3) all land, regardless of cost. Acquisitions of new assets, additions, replacements and improvements (other than land) costing less than the minimum rule in addition to maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred.

        During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt, and, in our regulated businesses that apply the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, or SFAS No. 71, an equity return component.

        We categorize our capital expenditures as either core maintenance or enhancement expenditures. Core maintenance expenditures are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment that are worn, obsolete or near the end of their useful lives. Examples of core maintenance expenditures include valve automation programs, cathodic protection, zero-hour compression overhauls and electrical switchgear replacement programs. Enhancement expenditures improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues, and enable us to respond to governmental regulations and developing industry standards. Examples of enhancement expenditures include costs associated with installation of seals, liners and other equipment to reduce the risk of environmental contamination from crude oil storage tanks, costs of sleeving a major segment of a pipeline system following an integrity tool run, natural gas or crude oil well-connects, natural gas plants and pipeline construction and expansion.

        Regulatory guidance issued by the FERC requires us to expense certain costs associated with implementing the pipeline integrity management requirements of the U.S. Department of Transportation's Office of Pipeline Safety. Under this guidance, beginning in January 2006, costs to 1) prepare a plan to implement the program, 2) identify high consequence areas, 3) develop and maintain a record keeping system and 4) inspect, test and report on the condition of affected pipeline segments to determine the need for repairs or replacements, are required to be expensed. We adopted this guidance prospectively in January 2006 for all our pipeline systems. Costs of modifying pipelines to permit in-line inspections, certain costs associated with developing or enhancing computer software and costs associated with remedial mitigation actions to correct an identified condition continue to be capitalized. We have historically capitalized initial in-line inspection programs, crack detection tool runs and hydrostatic testing costs conducted for the purposes of detecting manufacturing or construction defects. Beginning January 2006, costs of this nature are expensed as incurred, which is consistent with industry practice and the regulatory guidance issued by the FERC. However, we continue to capitalize initial construction hydrostatic testing cost and subsequent hydrostatic testing programs conducted for the purpose of increasing pipeline capacity in accordance with our capitalization policies. Also capitalized are certain costs such as sleeving or recoating existing pipelines, unless the expenditures are incurred as a single event and not part of a major program, in which case we expense these costs as incurred. Our adoption of the regulatory guidance did not significantly affect our financial position, results of operations or cash flows.

        We record property, plant and equipment at its original cost, which we depreciate on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the crude oil or natural gas production in the basins the assets serve. Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. We routinely utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

        We record depreciation using the group method of depreciation which is commonly used by pipelines, utilities and similar entities. Under the group method, for all segments, upon the disposition of property, plant and equipment, the cost less net proceeds is typically charged to accumulated depreciation and no

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gain or loss on disposal is recognized. However, when a separately identifiable group of assets, such as a stand-alone pipeline system is sold, we will recognize a gain or loss in our consolidated statements of income for the difference between the cash received and the net book value of the assets sold. Changes in any of our assumptions may alter the rate at which we recognize depreciation in our consolidated financial statements. At regular intervals, we retain the services of independent consultants to assist us with assessing the reasonableness of the useful lives we have established for the property, plant and equipment of our major systems. Based on the results of these regular assessments we may make modifications to the assumptions we use to determine our depreciation rates.

        We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost, contract renewals, and other factors. We recognize an impairment loss when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our consolidated statements of income.

Goodwill

        Goodwill represents the excess of the purchase price over the fair value of net assets acquired in a business combination. Goodwill is allocated to two of our segments, Natural Gas and Marketing.

        Goodwill is not amortized, but is tested for impairment annually based on carrying values as of the end of the second quarter, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. Impairment occurs when the carrying amount of a reporting unit exceeds its fair value. At the time we determine that impairment has occurred, the carrying value of the goodwill is written down to its fair value. To estimate the fair value of the reporting units, we make estimates and judgments about future cash flows, as well as revenue, cost of sales, operating expenses, capital expenditures and net working capital based on assumptions that are consistent with our most recent long range plan, which we use to manage the business. We have not identified or recognized any goodwill impairments during the years ended December 31, 2007, 2006 or 2005.

Intangibles, Net

        Intangibles, net, consist of customer contracts for the purchase and sale of natural gas and natural gas supply opportunities. We amortize these assets on a straight-line basis over the weighted average useful life of the underlying assets, representing the period over which the asset is expected to contribute directly or indirectly to our future cash flows.

        We evaluate the carrying value of our intangible assets whenever certain events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. In assessing the recoverability of intangibles, we compare the carrying value to the undiscounted future cash flows the intangibles are expected to generate. If the total of the undiscounted future cash flows is less than the carrying amount of the intangibles, the intangibles are written down to their fair value. We did not identify nor recognize any impairment of our intangible assets for the years ended December 31, 2007, 2006, or 2005.

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Other Assets

        Other assets primarily include deferred financing costs, which we amortize on a straight-line basis over the life of the related debt to interest expense on our consolidated statements of income. Amortization of these costs on a straight-line basis approximates the amortization computed using the effective interest method.

Income Taxes

        We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment, by the State of Texas, of a new state tax computed on our modified gross margin that we determined to be an income tax under the provisions of SFAS No. 109.

        We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. The impact of changes in tax legislation on deferred income tax liabilities and assets is recorded in the period of enactment.

        Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner's tax attributes in us is not available.

Derivative Financial Instruments

        Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt and commodity prices of natural gas, NGL, condensate and fractionation margins (the relative price differential between NGL sales and the offsetting natural gas purchases). In order to manage the risks to unitholders, we use a variety of derivative financial instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to create offsetting positions to specific commodity or interest rate exposures. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"), we record all derivative financial instruments on our consolidated statements of financial position at fair market value. We record the fair market value of our derivative financial instruments in the Consolidated Statements of Financial Position as current and long-term assets or liabilities on a net basis by counterparty. For those instruments that qualify for hedge accounting, the accounting treatment depends on the intended use and designation of each instrument. For our derivative financial instruments related to commodities that do not qualify for hedge accounting, the change in market value is recorded as a component of cost of natural gas in the consolidated statements of income. For our derivative financial instruments related to interest rates that do not qualify for hedge accounting, the change in fair market value is recorded as a component of Interest expense in the consolidated statements of income.

        In implementing our hedging programs, we have established a formal analysis, execution and reporting framework that requires the approval of the board of directors of Enbridge Management or a committee of our senior management. We employ derivative financial instruments in connection with an underlying asset, liability or anticipated transaction and we do not use derivative financial instruments for speculative purposes.

        Derivative financial instruments qualifying for hedge accounting treatment that we use can generally be divided into two categories: 1) cash flow hedges, or 2) fair value hedges. We enter into cash flow hedges to reduce the variability in cash flows related to forecasted transactions. We enter into fair value hedges to reduce the risk of changes in the value of recognized assets or liabilities.

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        Price assumptions we use to value the cash flow and fair value hedges can affect net income for each period. We use published market price information where available, or quotations from over-the-counter ("OTC") market makers to find executable bids and offers. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, modeling risk, credit risk of our counterparties and operational risk. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

        At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or the fair value of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

        For cash flow hedges, changes in the fair market values of derivative financial instruments, to the extent that the hedges are determined to be highly effective, are recorded as a component of Accumulated other comprehensive income until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge's change in fair market value is recognized immediately in earnings. For fair value hedges, the change in fair market value of the financial instrument is determined each period and is taken into earnings. In addition, the change in the fair market value of the hedged item is also calculated and taken into earnings. To the extent that the two valuations offset, the hedge is effective and net earnings is not affected.

        Our earnings are also affected by use of the mark-to-market method of accounting as required under GAAP for derivative financial instruments that do not qualify for hedge accounting. We use short-term, highly liquid derivative financial instruments such as basis swaps and other similar derivative financial instruments to economically hedge market price risks associated with inventories, firm commitments and certain anticipated transactions. However, these derivative financial instruments, do not qualify for hedge accounting treatment under SFAS No. 133, and thus the changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the "mark-to-market" method) rather than being deferred until the firm commitment or anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying indices, primarily commodity prices. The fair market value of these derivative financial instruments is determined using price data from highly liquid markets such as the New York Mercantile Exchange, or NYMEX, OTC market makers, or other similar sources.

Commitments, Contingencies and Environmental Liabilities

        We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. Amounts for remediation of existing environmental contamination caused by past operations, which do not benefit future periods by preventing or eliminating future contamination, are expensed. Liabilities are recorded when environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of the liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies' clean-up experience and data released by government organizations. These estimates are subject to revision in future periods based on actual costs or new information and are included on the balance sheet in other current and long-term liabilities at their undiscounted amounts. We evaluate recoveries from insurance coverage separately from the liability and,

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when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements.

        We recognize liabilities for other contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss. We typically expense legal costs associated with loss contingencies as such costs are incurred.

Asset Retirement Obligations

        We have legal obligations requiring us to decommission our offshore pipeline systems at retirement. In certain rate jurisdictions, we are permitted to include annual charges for removal costs in the regulated cost of service rates we charge our customers. Additionally, legal obligations exist for a minority of our onshore right-of-way agreements due to requirements or landowner options to compel us to remove the pipe at final abandonment. Sufficient data exists with certain onshore pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, management's intent, or the asset's estimated economic life. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to reasonably estimate potential settlement dates and methods.

        We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis, in the period in which the liability is incurred. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.

        We did not record any additional AROs for the years ended December 31, 2007 and 2006. We recorded accretion expense of $0.2 million, $0.2 million and $0.5 million, respectively, in the consolidated statements of income for the years ended December 31, 2007, 2006 and 2005 for previously recorded asset retirement obligation liabilities.

        No assets are legally restricted for purposes of settling our ARO for each of the years ended December 31, 2007 and 2006. Following is a reconciliation of the beginning and ending aggregate carrying amount of our ARO liabilities for each of the years ended December 31, 2007 and 2006:

 
   2007
   2006
 
   (in millions)
Balance at beginning of period   $ 3.8   $ 3.6
Disposal of KPC     (1.1 )   —
Accretion expense     0.2     0.2
   
 
Balance at end of period   $ 2.9   $ 3.8
   
 

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Recent Accounting Pronouncements Not Yet Adopted

Fair Value Measurements

        In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurement. The statement is effective for fiscal years beginning after November 15, 2007, and with limited exceptions is to be applied prospectively as of the beginning of the fiscal year initially adopted. We expect to adopt the provisions of this statement prospectively beginning January 1, 2008. We do not expect our adoption of this pronouncement to materially affect our consolidated financial statements. However, our adoption of this pronouncement may affect our disclosures regarding derivative financial instruments and indebtedness.

        In February 2007, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 159, The Fair Value Option for Financial Assets and Liabilities ("SFAS No. 159"). This statement provides companies with an option to report certain financial assets and financial liabilities at fair value. The objective of SFAS No. 159 is to reduce the volatility in earnings caused by measuring related financial assets and financial liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. The provisions of SFAS No. 159 are effective at the beginning of our first fiscal year that begins after November 15, 2007, as we have elected not to early adopt its provisions. We do not expect our adoption of SFAS No. 159 to have a material affect on our consolidated financial statements.

Business Combinations

        In December 2007, the Financial Accounting Standards Board issued Statement No. 141(R), Business Combinations, which we refer to as SFAS No. 141(R). The new standard retains the fundamental requirements in FASB Statement No. 141, Business Combinations, that the acquisition method of accounting (previously referred to as the purchase method), be used for all business combinations and for an acquirer to be identified for each business combination. Among other items, SFAS No. 141(R) requires the following:

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        SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, and early adoption is not permitted. The provisions of this statement will require us to expense certain costs associated with acquisitions that were previously permitted to be capitalized which may affect our operating results in periods that we complete an acquisition.

Noncontrolling Interests

        In December 2007, the Financial Accounting Standards Board issued FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51, to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for deconsolidation of a subsidiary. Among other provisions, SFAS No. 160 requires the following:

        SFAS No. 160 is effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2008, and early adoption is prohibited. SFAS No. 160 requires prospective adoption as of the beginning of the fiscal year in which the provisions are initially applied, except for the presentation and disclosure requirements which shall be applied retrospectively for all periods presented. Our adoption of this standard will not have a material effect on our financial position or results of operations.

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3. ACQUISITIONS AND DISPOSITIONS

        We accounted for each of our completed acquisitions using the purchase method and recorded the assets acquired and liabilities assumed at their estimated fair market values as of the date of purchase. We have included the results of operations from each of these acquisitions in our earnings from the acquisition date.

2007 Disposition

KPC Disposition

        In November 2007, we sold our Kansas pipeline system, or KPC, with a net asset value of approximately $100.4 million, including $9.2 million of goodwill, to an unrelated party for $133 million in cash, subject to adjustments for working capital items. KPC is an interstate natural gas transmission system, which serves the Wichita, Kansas and Kansas City, Kansas markets and includes approximately 1,120 miles of pipeline ranging in diameter from 4 to 12 inches, along with three compressor stations. The area in which KPC operates is not strategic to the ongoing central operations of our core Natural Gas segment assets. The operating results of the KPC system were not material to our consolidated operating results or those of our Natural Gas segment for the years ended December 31, 2007, 2006 and 2005. We recognized a gain of $32.6 million on the sale of KPC, which is presented in income from discontinued operations.

2006 Acquisitions

Oakhill Acquisition

        In April 2006, we acquired, for $33.3 million in cash, an 80-mile natural gas pipeline that is complementary to our existing East Texas system. This pipeline provides approximately 100 million cubic feet per day, or MMcf/d, of additional transportation capacity and interconnects with approximately 65 central receipt points.

        The purchase price and the allocation to assets acquired and liabilities assumed are as follows in millions of dollars:

Purchase Price:      
  Cash paid, including transaction costs   $ 33.3
   
Allocation of purchase price:      
  Property, plant and equipment, including construction in progress   $ 13.0
  Intangibles     12.8
  Goodwill     7.5
   
Total   $ 33.3
   

2005 Acquisitions and Dispositions

North Texas Natural Gas System

        In January 2005, we acquired natural gas gathering and processing assets in north Texas for $164.6 million in cash, including transaction costs of $0.5 million. The assets we acquired serve the Fort Worth Basin, which is mature, but experiencing minimal production decline rates and include:

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        The system provides cash flow primarily from purchasing raw natural gas from producers at the wellhead, processing the natural gas and then selling the natural gas liquids and residue natural gas streams. We included the assets and results of operations in our Natural Gas segment from the acquisition date.

        We allocated the purchase price of the assets acquired and liabilities assumed as follows (in millions):

Purchase Price:        
  Cash paid, including transaction costs   $ 164.6  
   
 
Allocation of purchase price:        
  Property, plant and equipment, including construction in progress   $ 151.6  
  Intangibles, including contracts     14.3  
  Current liabilities     (0.9 )
  Contingent liabilities     (0.4 )
   
 
Total   $ 164.6  
   
 

Other 2005 Acquisitions

        In June 2005, we acquired for $20.1 million in cash, a natural gas pipeline and related facilities consisting of 92 miles of 20-inch diameter pipeline that extends from Pampa, Texas into western Oklahoma and has interconnects with our Anadarko system. We integrated this pipeline into our existing Anadarko system and have included the assets and operating results in our Natural Gas segment from the date of acquisition. The purchase price for this acquisition was allocated to property, plant and equipment for $19.1 million and goodwill for $1.0 million. We also acquired other gathering and processing assets during 2005 that are complementary to our existing natural gas systems for cash totaling approximately $1.7 million.

Sale of Gathering and Processing Assets

        In December 2005, we sold for $105.4 million in cash, a processing plant and related facilities and other gathering and processing assets located in our East and South Texas systems with a carrying value of approximately $86.9 million. We incurred selling costs of approximately $0.4 million and recognized a gain on the sale of approximately $18.1 million. The facilities we sold represent non-strategic assets within our Natural Gas segment. In connection with this sale, we paid approximately $16.3 million to settle natural gas collars on 2,000 Million British Thermal units per day, or MMBtu/d, associated with the natural gas produced by these assets and entered into offsetting derivatives at market to close out derivatives previously classified as hedges of 273 Barrels per day, or Bpd, of NGL produced by these assets. We had previously recorded unrealized losses associated with the natural gas collars that were realized upon settlement. Refer to Note 14 for additional discussion regarding our derivative activities.

4. NET INCOME PER LIMITED PARTNER UNIT

        We compute net income per limited partner unit by dividing net income, after deducting our allocation to the General Partner, by the weighted average number of our limited partner units outstanding. The General Partner's allocation is equal to an amount based upon its general partner interest, adjusted to reflect an amount equal to its incentive distributions and an amount required to reflect depreciation on the General Partner's historical cost basis for assets contributed on formation of the

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Partnership. We have no dilutive securities, therefore basic and diluted earnings per unit amounts are equal. Net income per limited partner unit was determined as follows:

 
   Year ended December 31,
  
 
   2007
   2006
   2005
  
 
   (in millions,
except per unit amounts)

  
Income from continuing operations   $ 216.9   $ 284.9   $ 89.2  
Income from discontinued operations     32.6     —     —  
   
 
 
 
Net income   $ 249.5   $ 284.9   $ 89.2  
   
 
 
 
Allocations to the General Partner:                    
  Income from continuing operations   $ (4.3 ) $ (5.7 ) $ (1.8 )
  Incentive distributions to General Partner     (32.5 )   (25.1 )   (21.6 )
  Historical cost depreciation adjustments     (0.2 )   (0.1 )   (0.1 )
   
 
 
 
      (37.0 )   (30.9 )   (23.5 )
  Income from discontinued operations     (0.7 )   —     —  
   
 
 
 
    $ (37.7 ) $ (30.9 ) $ (23.5 )
   
 
 
 
Allocations to limited partner units                    
  Income from continuing operations   $ 179.9   $ 254.0   $ 65.7  
  Income from discontinued operations     31.9     —     —  
   
 
 
 
    $ 211.8   $ 254.0   $ 65.7  
   
 
 
 
Basic and diluted earnings per limited partner unit                    
  Income from continuing operations   $ 2.08   $ 3.62   $ 1.06  
  Income from discontinued operations     0.37     —     —  
   
 
 
 
Net income per limited partner unit (basic and diluted)   $ 2.45   $ 3.62   $ 1.06  
   
 
 
 
Weighted average units outstanding     86.3     70.2     62.1  
   
 
 
 

5. INVENTORY

        Inventory is comprised of the following:

 
   December 31,
 
   2007
   2006
 
   (in millions)
Material and supplies   $ 3.9   $ 3.8
Liquids inventory     6.7     9.9
Natural gas and natural gas liquids inventory     100.0     103.4
   
 
    $ 110.6   $ 117.1
   
 

        Our inventory at December 31, 2007 is net of charges totaling $4.5 million we recorded in 2007 to reduce the cost basis of our natural gas inventory to reflect market value. Our inventory at December 31, 2006 is net of charges totaling $17.7 million we recorded in 2006 to reduce the cost basis of our natural gas inventory to reflect market value. The lower of cost or market adjustments are included in the Cost of natural gas of our Natural Gas and Marketing segments on our consolidated statements of income.

F-23

6. PROPERTY, PLANT AND EQUIPMENT

        Property, Plant and Equipment is comprised of the following:

 
    
   December 31,
  
 
   Depreciation
Rates(1)
  
 
   2007
   2006
  
 
    
   (in millions)

  
Land   —   $ 14.3   $ 14.3  
Rights-of-way   1.5% -   6.4%     345.8     298.6  
Pipeline   1.5% -   7.0%     2,703.2     2,320.8  
Pumping equipment, buildings and tanks   1.5% - 14.3%     854.7     747.4  
Compressors, meters, and other operating equipment   1.5% - 20.0%     536.1     418.1  
Vehicles, office furniture and equipment   1.4% - 33.3%     123.3     112.4  
Processing and treating plants   2.7% -   4.0%     200.4     86.4  
Construction in progress   —     1,813.9     733.6  
       
 
 
  Total property, plant and equipment         6,591.7     4,731.6  
Accumulated depreciation         (1,036.8 )   (906.7 )
       
 
 
  Net property, plant and equipment       $ 5,554.9   $ 3,824.9  
       
 
 
(1)
We have assets included in the above table that are highly depreciated, which yield depreciation rates that suggest these assets have significant remaining useful lives, but in fact have little remaining net book value in relation to their expected service lives.

        Based on third-party studies commissioned by management, we implemented revised depreciation rates for the Lakehead system effective January 1, 2006, and the Anadarko, North Texas and East Texas systems effective August 1, 2005. We reduced the annual composite rate, representing the expected remaining service lives of the system assets, from 3.20% to 2.63% for our Lakehead system and from 4.0% to 3.4% for our Anadarko, North Texas and East Texas systems. As a result, our depreciation expense for the years ended December 31, 2006 and 2005, respectively, was approximately $14.5 million and $2.5 million lower than if these rates had not been reduced. Additionally, effective July 1, 2006, we increased the annual composite rates on three of our FERC-regulated pipelines, representing reductions to the expected remaining service lives of our AlaTenn, KPC, and Midla systems. These increases resulted in approximately $1.3 million and $2.6 million of additional depreciation in 2006 and 2007, respectively.

7. GOODWILL

        The changes in the carrying amount of goodwill for each of the years ended December 31, 2007 and 2006 are as follows:

 
   Liquids
   Natural Gas
   Marketing
   Corporate
   Total
  
 
   (in millions)

  
December 31, 2005   $ —   $ 237.8   $ 20.4   $ —   $ 258.2  
  Acquisition     —     7.5     —     —     7.5  
   
 
 
 
 
 
December 31, 2006     —     245.3     20.4     —     265.7  
  Disposition     —     (9.2 )   —     —     (9.2 )
   
 
 
 
 
 
December 31, 2007   $ —   $ 236.1   $ 20.4   $ —   $ 256.5  
   
 
 
 
 
 

        In November 2007 we sold our KPC assets to an unrelated third party for $133 million. In connection with the sale, we disposed of $9.2 million of goodwill associated with this business which we reduced the gain we realized from the sale.

        We completed our annual goodwill impairment test using data at June 30, 2007. To estimate the fair value of our reporting units we made estimates and judgments about future cash flows, as well as revenue,

F-24


cost of sales, operating expenses, capital expenditures, and net working capital based on assumptions that are consistent with the long-range plans we use to manage our businesses. Based on the results of our impairment analysis, we determined that the fair value of each reporting unit exceeded its respective carrying amount, including goodwill. As a result, no goodwill impairment existed in any of our reporting units. We have not observed any events or circumstances subsequent to our analysis that would, more likely than not, reduce the fair value of our reporting units below the carrying amounts as of December 31, 2007.

8. INTANGIBLES

        The following table provides the gross carrying value, accumulated amortization and activity affecting these balances for each of our major classes of intangible assets.

 
   Gross Carrying Amount
   Accumulated Amortization
    
  
 
   Customer
Contracts
   Natural Gas
Supply
Opportunities
   Other
   Intangible
Assets
Gross
   Customer
Contracts
   Natural Gas
Supply
Opportunities
   Other
   Accumulated
Amortization
Gross
   Intangible
Assets,
Net
  
 
   (in millions)

  
December 31, 2004   $ 31.1   $ 48.1   $ —   $ 79.2   $ (3.3 ) $ (1.9 ) $ —   $ (5.2 ) $ 74.0  
   
 
 
 
 
 
 
 
 
 
  Additions     14.3     —     4.3     18.6     —     —     —     —     18.6  
  Dispositions     (2.2 )   —     —     (2.2 )   0.3     —     —     0.3     (1.9 )
  Amortization     —     —     —     —     (1.7 )   (2.0 )   (0.1 )   (3.8 )   (3.8 )
   
 
 
 
 
 
 
 
 
 
December 31, 2005     43.2     48.1     4.3     95.6     (4.7 )   (3.9 )   (0.1 )   (8.7 )   86.9  
   
 
 
 
 
 
 
 
 
 
  Additions     12.8     —     2.4     15.2     —     —     —     —     15.2  
  Amortization     —     —     —     —     (2.2 )   (1.9 )   (0.2 )   (4.3 )   (4.3 )
   
 
 
 
 
 
 
 
 
 
December 31, 2006     56.0     48.1     6.7     110.8     (6.9 )   (5.8 )   (0.3 )   (13.0 )   97.8  
   
 
 
 
 
 
 
 
 
 
  Additions     —     —     2.9     2.9     —     —     —     —     2.9  
  Dispositions(1)     (5.8 )   —     —     (5.8 )   1.1     —     —     1.1     (4.7 )
  Amortization     —     —     —     —     (2.2 )   (1.9 )   (0.4 )   (4.5 )   (4.5 )
   
 
 
 
 
 
 
 
 
 
December 31, 2007   $ 50.2   $ 48.1   $ 9.6   $ 107.9   $ (8.0 ) $ (7.7 ) $ (0.7 ) $ (16.4 ) $ 91.5  
   
 
 
 
 
 
 
 
 
 
(1)
We disposed of customer contract intangibles of $4.7 million in connection with the sale of KPC.

        Our customer contracts are comprised entirely of natural gas purchase and sale agreements associated with our Natural Gas and Marketing segments. We amortize our customer contracts on a straight-line basis over the weighted average useful life of the underlying reserves at the time of acquisition, which approximates 25 years.

        We obtained the natural gas supply opportunities in conjunction with the 2003 North Texas system acquisition and relate entirely to our Natural Gas segment. The value of the intangible asset was determined by a third party appraisal and it represents the fair value associated with growth opportunities present in the Barnett Shale producing zone. We are amortizing the natural gas supply opportunities over the weighted average estimated useful life of the underlying reserves at the time of the acquisition, which approximates 25 years.

F-25

        Our other column is comprised of contributions we made in aid of construction for our Natural Gas and Liquids business. We made contributions to third parties for construction of electrical infrastructure to provide utility services for our Lakehead system and for interconnections between our natural gas systems and third-party pipelines and the related measurement equipment.

        We estimate the aggregate amortization expense associated with our intangibles for each of the five succeeding years through December 31, 2012 to approximate $4.6 million.

9. DEBT

        The following table presents the primary components of our outstanding indebtedness and the weighted average interest rates associated with each component at the end of each period presented, before the effect of our interest rate hedging activities as discussed in Notes 13 and 14:

 
   December 31,
  
 
    
   2007
   2006
  
 
   Maturity
   Rate
   Dollars
   Rate
   Dollars
  
 
   (dollars in millions)

  
First Mortgage Notes   2011   9.15 % $ 124.0   9.15 % $ 155.0  
Credit Facility   2012   5.22 %   400.0   —     —  
Commercial Paper(1)   2012   5.36 %   268.5   5.45 %   443.7  
Senior Notes   2009-2034   5.69 %   1,702.1   5.74 %   1,498.4  
Junior Subordinated Notes   2067   8.05 %   399.3   —     —  
           
     
 
              2,893.9         2,097.1  
Current maturities and short-term debt             (31.0 )       (31.0 )
           
     
 
Long-term debt           $ 2,862.9       $ 2,066.1  
           
     
 
(1)
Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our credit facility and are therefore considered long-term debt.

First Mortgage Notes

        The First Mortgage Notes ("Notes") are collateralized by a first mortgage lien on substantially all of the property, plant and equipment of the Enbridge Energy, Limited Partnership, (the "OLP"), and are due and payable in equal annual installments of $31.0 million until their maturity in 2011. Property, plant and equipment, net, associated with the OLP was $2,555.5 million and $1,495.1 million at December 31, 2007 and 2006, respectively. The Notes contain various restrictive covenants applicable to us, and restrictions on the incurrence of additional indebtedness, including compliance with certain debt issuance tests. We believe these restrictions will not negatively impact our ability to finance future expansion projects. Under the Notes agreements, we cannot make cash distributions more frequently than quarterly in an amount not to exceed Available Cash (see Note 10) for the immediately preceding calendar quarter. We would be required to pay a redemption premium pursuant to the Note agreements should we elect to repay the Notes prior to their stated maturity.

        Under the terms of the Notes, we are required to establish, at the end of each quarter, a debt service reserve. This reserve includes an amount equal to 50% of the prospective Notes interest payments for the immediately following quarter and an amount for Note sinking fund repayments. At December 31, 2007 and 2006, there was no required debt service reserve, as we have made all required interest and sinking fund payments.

F-26

Credit Facility

        On April 4, 2007 we entered into the Second Amended and Restated Credit Agreement (Credit Facility) which among other things: (i) increased the maximum principal amount of credit available to us at any one time from $1 billion to $1.25 billion; (ii) gave us the right to request increases in the maximum principal amount of credit available at any one time from $1.25 billion to $1.5 billion; (iii) eliminated the sublimit on letters of credit; (iv) provided for a five-year facility that matures April 4, 2012 and grants us the option to request annual extensions of maturity and a one-year term out period upon maturity; (v) modified our leverage ratio to include in the calculations of EBITDA (as defined in the Second Amended and Restated Credit Agreement) pro forma adjustments for material projects and to exclude from the calculation of Consolidated Funded Debt (as defined in the Second Amended and Restated Credit Agreement) certain amounts of preferred securities and subordinated debt that we or our designated subsidiaries may issue in the future; and (vi) eliminated our coverage ratio financial covenant. Our Credit Facility contains restrictive covenants that require us to maintain a maximum leverage ratio of 5.50 to 1.0 for periods ending on or before March 31, 2009; a ratio of 5.25 to 1.0 thereafter, for periods ending on or before March 31, 2010; and a ratio of 5.00 to 1.0 for periods ending June 30, 2010 and following. Our Credit Facility continues to support our commercial paper program.

        At December 31, 2007, our leverage ratio was approximately 3.6. 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.

        At December 31, 2007, we had $400 million outstanding under our Credit Facility at a weighted average interest rate of 5.22% and letters of credit totaling $159.7 million. The amounts we may borrow under the terms of our Credit Facility are reduced by the principal amount of our commercial paper issuances and the balance of our letters of credit outstanding. At December 31, 2007 and 2006, we could borrow $420.3 million and $495.7 million, respectively, under the terms of our Credit Facility, determined as follows:

 
   2007
   2006
  
 
   (in millions)

  
Total credit available under Credit Facility   $ 1,250.0   $ 1,000.0  
Less:  Amounts outstanding under Credit Facility     (400.0 )   —  
           Balance of letters of credit outstanding     (159.7 )   (59.3 )
           Principal amount of commercial paper issuances     (270.0 )   (445.0 )
   
 
 
Total amount we could borrow at December 31, 2007   $ 420.3   $ 495.7  
   
 
 

        Individual borrowings under the terms of our Credit Facility generally become due and payable at the end of each contract period, typically a period of three months or less. We have the option to repay these amounts on a non-cash basis by net settling with the parties to our Credit Facility by contemporaneously borrowing at the then current rate of interest and repaying the amounts due. During the year ended December 31, 2007, we net settled borrowings of approximately $180 million on a non-cash basis. During the year ended December 31, 2006, we did not net settle any borrowings under our Credit Facility and we net settled $565 million during the year ended December 31, 2005, on a non-cash basis.

Commercial Paper Program

        We have a commercial paper program that provides for the issuance of up to $600 million of commercial paper that is supported by our Credit Facility. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions, at rates that are generally lower than the rates available under our Credit Facility. At December 31, 2007 and 2006, respectively, we had $268.5 million and $443.7 million of commercial paper outstanding, net of unamortized discount of $1.5 million and $1.3 million, at weighted average interest rates of 5.36% and

F-27


5.45%. At December 31, 2007 and 2006, respectively, we could issue an additional $330 million and $155 million in principal amount under our commercial paper program.

        We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis under our unsecured long-term Credit Facility. Accordingly, such amounts have been classified as long-term debt in our accompanying consolidated statement of financial position.

Senior Notes

        All of our Senior Notes, other than the Zero Coupon Notes discussed below, pay interest semi-annually and have varying maturities and terms as presented in the following table. The Senior Notes do not contain any covenants restricting the issuance of additional indebtedness and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness. The interest rates set forth in this table represent the interest rates as set forth on the face of each note agreement without consideration to any discount or interest rate hedging activities.

 
    
   December 31,
  
 
   Interest
Rate
  
 
   2007
   2006
  
 
    
   (in millions)

  
Senior Notes due 2009   4.000 % $ 200.0   $ 200.0  
Senior Notes due 2012   7.900 %   100.0     100.0  
Senior Notes due 2013   4.750 %   200.0     200.0  
Senior Notes due 2014   5.350 %   200.0     200.0  
Senior Notes due 2016   5.875 %   300.0     300.0  
Senior Notes due 2018   7.000 %   100.0     100.0  
Senior Notes due 2028   7.125 %   100.0     100.0  
Senior Notes due 2033   5.950 %   200.0     200.0  
Senior Notes due 2034   6.300 %   100.0     100.0  
Senior, unsecured zero coupon notes due 2022   5.358 %   203.6     —  
       
 
 
          1,703.6     1,500.0  
Unamortized Discount         (1.5 )   (1.6 )
       
 
 
          1,702.1     1,498.4  
       
 
 

Zero Coupon Senior Notes

        In August 2007, we received net proceeds of approximately $200 million from a private placement of our senior, unsecured zero coupon notes due 2022 (the "Zero Coupon Notes"), which at maturity will be payable in the aggregate principal amount of $442 million. We initially recorded the Zero Coupon Notes in long-term debt at the amount of proceeds we received from the private placement, which we refer to as the issue price. The carrying amount at December 31, 2007 includes $3.6 million associated with the accretion of interest we recognized as interest expense during the period. The Zero Coupon Notes are scheduled to mature on August 28, 2022, although they may be called by the note holders prior to the scheduled maturity date on August 28 of any year commencing on August 28, 2009, at a price equal to the then accreted value of the called Zero Coupon Notes. The Zero Coupon Notes have a yield of 5.36% on a semi-annual compound basis and rank equally in right of payment to all of our existing and future senior indebtedness, as set forth in our senior indenture. We used the net proceeds from this private placement to repay a portion of our outstanding commercial paper and Credit Facility borrowings that we had previously incurred to fund a portion of our capital expansion projects.

F-28

Junior Subordinated Notes

        In September 2007, we issued and sold $400 million in principal amount of our fixed/floating rate, junior subordinated notes due 2067, which we refer to as the Junior Notes. We received proceeds of approximately $393 million, net of underwriting discounts, commissions and offering expenses. We used the net proceeds to temporarily reduce a portion of our outstanding commercial paper and Credit Facility borrowings that we had previously incurred to finance a portion of our capital expansion projects.

        The Junior Notes represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness. The Junior Notes bear interest at a fixed annual rate of 8.05%, exclusive of any discounts or interest rate hedging activities, from September 27, 2007 to October 1, 2017, payable semi-annually in arrears on April 1 and October 1 of each year beginning April 1, 2008. After October 1, 2017, the Junior Notes will bear interest at a variable rate equal to the three-month LIBOR for the related interest period increased by 3.7975%, payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2018. We may elect to defer interest payments on the Junior Notes for up to ten consecutive years on one or more occasions, but not beyond the final repayment date. Until paid, any interest we elect to defer will bear interest at the prevailing interest rate, compounded semi-annually during the period the Junior Notes bear interest at the fixed annual rate and quarterly during the period that the Junior Notes bear interest at a variable annual rate.

        The Junior Notes do not restrict our ability to incur additional indebtedness. However, with limited exceptions, during any period we elect to defer interest payments on the Junior Notes, we cannot make distribution payments or liquidate any of our equity securities, nor can we or our subsidiaries make any principal and interest payments for any debt that ranks equally with or junior to the Junior Notes.

        The scheduled maturity date for the Junior Notes is initially October 1, 2037, but we may extend the maturity date up to two times, on October 1, 2017 and October 1, 2027, in each case for an additional ten-year period. As a result, the scheduled maturity date may be extended to October 1, 2047 or October 1, 2057. Our obligation to repay the Junior Notes on the scheduled maturity date is limited by an agreement we refer to as the Replacement Capital Covenant, which we entered into in connection with our offering of the Junior Notes, but not as part of the Junior Notes. The Replacement Capital Covenant limits the types of financing sources we can use to repay the Junior Notes. We are required to repay the Junior Notes on the scheduled maturity date only to the extent the principal amount repaid does not exceed proceeds we have received from the issuance and sale of securities, that, among other attributes defined in the Replacement Capital Covenant, have characteristics that are the same or more equity-like than the Junior Notes. We refer to the securities that meet this characterization as qualifying capital securities. If we do not receive sufficient proceeds from the sale of qualifying capital securities to repay the Junior Notes by the scheduled maturity date, we must use our commercially reasonable efforts to raise sufficient proceeds from the sale of qualifying capital securities to permit repayment of the Junior Notes on the following quarterly interest payment date, and on each subsequent quarterly interest payment date until the Junior Notes are paid in full. Regardless of the amount of qualifying capital securities that we have issued and sold, the final repayment date is initially October 1, 2067. We may extend the final repayment date for an additional ten-year period on October 1, 2017, and as a result the final repayment date may be extended to October 1, 2077. We may extend the scheduled maturity date whether or not we also extend the final repayment date, and we may extend the final repayment date whether or not we extend the scheduled maturity date.

        We may redeem the Junior Notes in whole at any time, or in part from time, prior to October 1, 2017, for a "make-whole" redemption price, and thereafter at a redemption price equal to the principal amount plus accrued and unpaid interest on the Junior Notes. We may also redeem the Junior Notes prior to October 1, 2017 in whole, but not in part, upon the occurrence of certain tax or rating agency events at specified redemption prices. Our right to optionally redeem the Junior Notes is also limited by the Replacement Capital Covenant, which limits the types of financing sources we can use to redeem the Junior Notes in the same manner as to repay the Junior Notes, as discussed in the above paragraph.

F-29

Interest

        For the years ended December 31, 2007, 2006, and 2005, our interest cost is comprised of the following:

 
   Year Ended December 31,
 
   2007
   2006
   2005
 
   (dollars in millions)
Interest expense   $ 99.8   $ 110.5   $ 107.7
Interest capitalized     47.4     10.7     4.0
   
 
 
Interest cost incurred   $ 147.2   $ 121.2   $ 111.7
   
 
 
Interest paid   $ 125.8   $ 109.7   $ 101.7
   
 
 

Maturities of Third Party Debt

        The scheduled maturities of outstanding third party debt, excluding the market value of interest rate swaps, at December 31, 2007, are summarized as follows in millions:

2008   $ 31.0
2009     434.6
2010     31.0
2011     31.0
2012     770.0
Thereafter     1,600.0
   
Total   $ 2,897.6
   

10. PARTNERS' CAPITAL

        Our capital accounts are comprised of a two percent general partner interest and 98 percent limited partner interests. The limited partner interests are comprised of Class A common units, Class B common units, Class C units, and i-units. The limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. The General Partner manages our operations, subject to a delegation of control agreement with Enbridge Management, and participates in the Partnership's distributions, including certain incentive income distributions.

Class A common units

        The following table presents the net proceeds from our Class A common unit issuances for each of the years ended December 31, 2007, 2006 and 2005. The proceeds from each of our offerings were generally used to repay issuances of commercial paper or amounts outstanding under our credit facilities, which we initially borrowed to finance our capital expansion projects and acquisitions, or to repay other outstanding obligations. Any proceeds we received in excess of amounts used to repay issuances of commercial paper

F-30


and credit facility borrowings were temporarily invested for use in future periods to fund additional expenditures associated with our capital expansion projects.

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 per unit amounts)
2007                            
May   5,300,000   $ 58.000   $ 301.9   $ 6.1   $ 308.0
   
       
 
 
2006                            
We did not issue any Class A common units during 2006                  

2005
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December   136,200   $ 46.000   $ 6.0   $ 0.2   $ 6.2
November   3,000,000   $ 46.000     132.1     2.8     134.9
February   2,506,500   $ 49.875     124.8     2.7     127.5
   
       
 
 
2005 Totals   5,642,700         $ 262.9   $ 5.7   $ 268.6
   
       
 
 
(1)
Net of underwriters' fees and discounts, commissions and issuance expenses.

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

Class B common units

        Our outstanding Class B common units are held entirely by our general partner and have rights similar to our Class A common units except that they are not currently eligible for trading on the NYSE.

Class C units

        In April 2007, we issued and sold 4.7 million Class C units at a price of $53.11 per Class C unit to CDP Infrastructure Fund G.P. ("CDP"), 0.9 million Class C units to Tortoise Infrastructure Corporation and 0.3 million Class C units to Tortoise Energy Capital Corporation. We sold the Class C units in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. We received proceeds of approximately $314.4 million, net of expenses associated with the private placement. In addition, our general partner contributed approximately $6.4 million to us to maintain its two percent general partner interest. We used the proceeds from this offering partially to reduce outstanding commercial paper we previously issued to finance a portion of our capital expansion program.

        In August 2006, we issued and sold 5.4 million Class C units, representing a new class of limited partner interest, to our general partner and 5.4 million Class C units to CDP for a purchase price of $46.00 per unit in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. We received proceeds of approximately $500 million, net of expenses associated with the private placement. Additionally, our general partner contributed approximately $10 million to maintain its two percent general partner interest.

i-units

        The i-units are a separate class of our limited partner interests, all of which are owned by Enbridge Management and are not publicly traded.

F-31

        Enbridge Management, as the owner of our i-units, votes together with the holders of the common units as a single class. However, the i-units vote separately as a class on the following matters:

        In all cases, Enbridge Management will vote or refrain from voting its i-units in the same manner that owners of Enbridge Management's shares vote or refrain from voting their shares. Furthermore, under the terms of our partnership agreement, we agree that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as the i-units.

Distributions

        Our partnership agreement requires us to distribute 100 percent of our "Available Cash", which is generally defined in our partnership agreement as the sum of all cash receipts and net additions to reserves for future cash requirements less cash disbursements and amounts retained by us. Enbridge Management, as delegate of our general partner under the delegation of control agreement, computes the amount of our "Available Cash." Typically, the General Partner and owners of our common units will receive distributions in cash. However, we also retain reserves to provide for the proper conduct of our business and as necessary to comply with the terms of our agreements or obligations (including any reserves required under debt instruments for future principal and interest payments and for future capital expenditures). We make distributions to our partners approximately 45 days following the end of each calendar quarter in accordance with their respective percentage interests.

        Our general partner is granted discretion by our partnership agreement, which discretion has been delegated to Enbridge Management, subject to the approval of the General Partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Enbridge Management determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

        Distributions of our Available Cash are generally made 98.0 percent to holders of our limited partner units and two percent to our general partner. However, distributions are subject to the payment of incentive distributions to the General Partner to the extent that certain target levels of distributions to the unitholders are achieved. The incremental incentive distributions payable to the General Partner are 15.0 percent, 25.0 percent and 50.0 percent of all quarterly distributions of Available Cash that exceed target levels of $0.59, $0.70, and $0.99 per limited partner units. As set forth in our partnership agreement, we will not make cash distributions on our i-units, but instead, will distribute additional i-units such that the cash is retained and used in our business. Similarly, until August 15, 2009, we will distribute additional Class C units to the holders of our Class C units in lieu of cash distributions, which will be retained and used in our business. Further, we retain an additional amount equal to two percent of the i-unit and Class C unit distributions from the General Partner to maintain its two percent general partner interest in us.

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        Enbridge Management, as owner of the i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution to the General Partner and the holders of our common units, the number of i-units owned by Enbridge Management and the percentage of our total units owned by Enbridge Management will increase automatically under the provisions of our partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management's listed and voting shares that are then outstanding. The amount of this increase in i-units is determined by dividing the cash amount distributed per common unit by the average price of one of Enbridge Management's listed shares on the NYSE for the 10-trading day period immediately preceding the ex-dividend date for Enbridge Management's shares multiplied by the number of shares outstanding on the record date. The cash equivalent amount of the additional i-units is treated as if it had actually been distributed for purposes of determining the distributions to be made to the General Partner.

        Until August 15, 2009, in lieu of cash distributions, the holders of our Class C units will receive quarterly distributions of additional Class C units with a value equal to the quarterly cash distributions we pay to the holders of our Class A and Class B common units, which we collectively refer to as common units. The number of additional Class C units we will issue is determined by dividing the quarterly cash distribution per unit we pay on our common units by the average market price of a Class A common unit as listed on the New York Stock Exchange for the 10-trading day period immediately preceding the ex-dividend date for our Class A common units multiplied by the number of Class C units outstanding on the record date. As a result, the number of Class C units and the percentage of our total units owned by holders of the Class C units will increase automatically under the provisions of our partnership agreement. The cash equivalent amount of the additional Class C units is treated as if it had actually been distributed for purposes of determining the distributions to be made to the General Partner.

        After August 15, 2009, the holders of our Class C units will receive quarterly cash distributions equal to those paid to the holders of our common units. Subject to the approval of holders of our outstanding units in accordance with the then-existing requirements of the principal national securities exchange on which the Class A common units are listed, the Class C units will convert into Class A common units on a one-for-one basis. If our unitholders do not approve the conversion, the holders of our Class C units will receive quarterly cash distributions equal to 115 percent of those paid to the holders of our common units. Prior to conversion, holders of our Class C units will not be entitled to receive any quarterly cash distribution until the holders of our common units have received a quarterly cash distribution of $0.59 per common unit.

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        The following table sets forth our distributions, as approved by the board of directors for each period in the years ended December 31, 2007, 2006 and 2005.

Distribution
Declaration
Date
   Distribution
Payment Date
   Record
Date
   Distribution
per Unit
   Cash
available for
distribution
   Amount of
Distribution
of i-units
to i-unit
Holders(1)
   Amount of
Distribution
of Class C
units
to Class C
unit
Holders(2)
   Retained
from
General
Partner(3)
   Distribution
of Cash
 
   (in millions, except per unit amounts)
2007                                            
October 29   November 14   November 6   $ 0.950   $ 96.0   $ 12.7   $ 16.8   $ 0.6   $ 65.9
July 27   August 14   August 6     0.925     92.6     12.1     16.2     0.6     63.7
April 26   May 15   May 7     0.925     86.6     11.9     15.9     0.6     58.2
January 26   February 14   February 6     0.925     80.0     11.7     10.2     0.5     57.6
                 
 
 
 
 
                  $ 355.2   $ 48.4   $ 59.1   $ 2.3   $ 245.4
                 
 
 
 
 
2006                                            
October 27   November 14   November 6   $ 0.925   $ 79.6   $ 11.5   $ 10.1   $ 0.4   $ 57.6
July 28   August 14   August 4     0.925     68.1     11.3     —     0.2     56.6
April 27   May 15   May 5     0.925     67.8     11.0     —     0.2     56.6
January 30   February 14   February 7     0.925     67.6     10.8     —     0.2     56.6
                 
 
 
 
 
                  $ 283.1   $ 44.6   $ 10.1   $ 1.0   $ 227.4
                 
 
 
 
 
2005                                            
October 26   November 14   November 3   $ 0.925   $ 64.1   $ 10.6   $ —   $ 0.2   $ 53.3
July 28   August 12   August 5     0.925     64.0     10.5     —     0.2     53.3
April 25   May 13   May 4     0.925     63.8     10.3     —     0.2     53.3
January 24   February 14   February 3     0.925     61.0     10.1     —     0.2     50.7
                 
 
 
 
 
                  $ 252.9   $ 41.5   $ —   $ 0.8   $ 210.6
                 
 
 
 
 
(1)
We issued 889,938, 969,200 and 802,539 i-units to Enbridge Energy Management, L.L.C., the sole owner of our i-units, during 2007, 2006 and 2005, respectively, in lieu of cash distributions.

(2)
We issued 1,072,423 and 200,587 additional Class C units to our Class C unitholders in lieu of cash distributions during 2007 and 2006, including 385,032 and 100,293 to our general partner, respectively.

(3)
We retained an amount equal to 2 percent of the i-unit and Class C unit distribution from the General Partner to maintain its 2 percent general partner interest in us.

11. RELATED PARTY TRANSACTIONS

Administrative and Workforce Related Services

        Enbridge and its affiliates provide management and administrative, operations and workforce related services to us. Employees of Enbridge and its affiliates are assigned to work for one or more affiliates of Enbridge, including us. Where directly attributable, the costs of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the services charged to us.

        The portion of direct workforce costs associated with the management and administrative services provided at our Houston office and the operating and administrative services provided to support our facilities across the United States, are charged to us by Enbridge and its affiliates.

        Certain of the operating activities associated with our Liquids segment are provided by Enbridge Pipelines Inc. ("Enbridge Pipelines"), a subsidiary of Enbridge, as the majority of these pipeline systems form one contiguous system with the Enbridge system in Canada. These services include control center operations, facilities management, shipper services, pipeline integrity management and other related activities. The costs to provide these services are allocated to us from Enbridge Pipelines, based on an

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appropriate allocation methodology consistent with Enbridge's corporate cost allocation policy, including estimated time spent and miles of pipe. We also receive costs associated with control center services for some of the natural gas assets from another affiliate of Enbridge.

        Enbridge also allocates management and administrative costs to us pursuant to our partnership agreement and related services agreements. These costs are allocated to us based on an allocation methodology consistent with Enbridge's corporate cost allocation policy, including estimated time spent, number of full-time equivalent employees and capital employed.

        During 2007, 2006 and 2005, we incurred the following costs related to these services, which are included in operating and administrative expenses.

 
   Year ended December 31,
 
   2007
   2006
   2005
 
   (in millions)
Direct workforce costs   $ 181.6   $ 152.1   $ 111.3
Allocated Liquids and Natural Gas operating costs     20.1     17.3     15.3
Allocated management and administrative costs, including insurance     28.9     27.4     20.1
   
 
 
    $ 230.6   $ 196.8   $ 146.7
   
 
 

        Enbridge and its affiliates allocated direct workforce costs to us related to our construction projects of $18.1 million, $11.8 million and $5.7 million during 2007, 2006 and 2005, respectively, that we recorded as additions to property, plant and equipment on our consolidated statements of financial position.

Affiliate Revenues and Purchases

        We purchase natural gas from third-parties, which subsequently generates operating revenues from sales to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale. We also record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates. Included in our results for the twelve months ending December 31, 2007, 2006 and 2005, are operating revenues of $95.2 million, $42.8 million, and $43.6 million, respectively, related to these transactions.

        In 2007, we entered into an agreement with Enbridge Pipelines Inc., a wholly-owned subsidiary of Enbridge, to install and operate certain sampling and related facilities for the purpose of improving the quality of crude oil and the transportation services on our Lakehead system, which directly increases the transportation services revenue of Enbridge Pipelines Inc. As compensation for installing and operating these transportation facilities, Enbridge Pipelines Inc. makes annual payments to us on a cost of service basis. The income we accrued for providing these transportation services in 2007 was approximately $0.6 million.

        We also purchase natural gas from Enbridge and its affiliates for sale to third-parties at market prices on the date of purchase. Included in our results for the twelve months ending December 31, 2007, 2006 and 2005, are cost of natural gas expenses of $6.2 million, $11.5 million and $4.5 million, respectively, relating to these purchases.

Notes Payable to Affiliates

Hungary Note Payable

        As of December 31, 2007 and 2006, we had $130.0 million and $136.2 million, respectively, in amounts outstanding under notes payable to Enbridge Hungary Ltd., an affiliate of our general partner, which we refer to as the Hungary Note. In December 2007, we repaid $145.0 million of the original Hungary Note, including $8.8 million of accrued interest, with proceeds we received from entering into a new Hungary

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Note agreement with substantially the same terms and approximately $15 million from our existing cash. The new Hungary Note bears interest at a fixed rate of 8.4% per annum that is payable semi-annually in June and December of each year through its maturity in December 2017. Similar to the old Hungary Note, the new note allows us the option of paying accrued and unpaid interest in the form of additional indebtedness by increasing the principal balance of the note for the amounts due. Consistent with the original Hungary Note, the new Hungary Note has cross-default provisions that are triggered by events of default under our First Mortgage Notes or defaults under our Credit Facility. The new Hungary Note is subordinate to our Credit Facility and other senior indebtedness, and ranks equally with current and future Junior Notes. We entered into the original Hungary Note agreement in connection with our acquisition of the Midcoast system in October 2002. For the year ended December 31, 2006, we converted interest payable in the amount of $4.4 million into debt by increasing the principal balance of the original Hungary Note.

EUS Credit Agreement

        In December 2007, we entered into an unsecured revolving credit agreement (the "EUS Credit Agreement") with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge. Enbridge is the indirect owner of Enbridge Energy Company, Inc., our general partner. The EUS Credit Agreement provides for a maximum principal amount of credit available to us at any one time of $500 million for a three-year term that matures in December 2010. The EUS Credit Agreement also includes financial covenants that are consistent with those in our Second Amended and Restated Credit Agreement as discussed above. Amounts borrowed under the EUS Credit Agreement bear interest at rates that are consistent with the interest rates set forth in our Second Amended and Restated Credit Agreement. At December 31, 2007, we had no balances outstanding under the EUS Credit Agreement and the full amount remains available for our use.

General Partner Equity Transactions

        Our general partner owns an effective two percent general partner ownership interest in us. Pursuant to our partnership agreement we paid cash distributions to our general partner of $34.9 million, $28.1 million, and $25.3 million for the years ended December 31, 2007, 2006 and 2005, respectively. The cash distributions we make to our general partner exclude an amount equal to two percent of the i-unit and Class C unit distributions, which we retain from the General Partner to maintain its two percent ownership interest in us.

        As of December 31, 2007 and 2006, the General Partner also owned 3,912,750 Class B common units, representing a 4.2 and 4.9 percent limited partner interest in us for the respective years. We paid the General Partner cash distributions of $14.5 million for the years ended December 31, 2007, 2006 and 2005, related to its ownership of Class B common units.

        At December 31, 2007 and 2006, our general partner owned 5,920,108 and 5,535,076 of our Class C units. We distributed 385,032 and 100,293 additional Class C units to our general partner during the years ended December 31, 2007 and 2006, respectively, in lieu of making cash distributions. The Class C units owned by our general partner at December 31, 2007 and 2006 represent an approximately 6.4 percent and 7.0 percent limited partner interest in us. Refer to Note 10 for additional information regarding the Class C units.

        In May 2007, we issued and sold 5.3 million of our Class A common units to the public for $58.00 per Class A common unit. As part of this transaction our general partner contributed approximately $6.1 million to us to maintain its two percent general partner interest.

        In April 2007, we issued and sold 5.9 million Class C units at a price of $53.11 per Class C unit to institutional investors. As part of this transaction our general partner contributed approximately $6.4 million to us to maintain its two percent general partner interest.

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        In August 2006, we sold approximately 5.4 million of our Class C units to our general partner for $250 million, or $46.00 per unit and 5.4 million Class C units to institutional investors for $250 million. As part of this transaction our general partner contributed approximately $10.2 million to maintain its two percent general partner interest.

Conflicts of Interest

        Enbridge Management makes all decisions relating to the management and control of our business through a delegation of control agreement with the General Partner and us. The General Partner owns the voting shares of Enbridge Management and elects all of Enbridge Management's directors. Enbridge, through its wholly-owned subsidiary, Enbridge Pipelines, owns all the common stock of the General Partner. Some of the General Partner's directors and officers are also directors and officers of Enbridge and Enbridge Management and have fiduciary duties to manage the business of Enbridge and Enbridge Management in a manner that may not be in the best interests of our unitholders. Certain conflicts of interest could arise as a result of the relationships among Enbridge Management, the General Partner, Enbridge and us. Our partnership agreement and the delegation of control agreement contain provisions that allow Enbridge Management to take into account the interest of all parties in addition to those of our unitholders in resolving conflicts of interest, thereby limiting its fiduciary duties to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.

Enbridge Management

        Pursuant to the delegation of control agreement between Enbridge Management, our General Partner and us, and our partnership agreement, we pay all expenses relating to Enbridge Management. This includes Texas franchise taxes and any other similar capital-based foreign, state and local taxes not otherwise paid or reimbursed pursuant to a tax indemnification agreement between Enbridge and Enbridge Management on behalf of Enbridge Management.

12. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

        We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover environmental liabilities associated with the Lakehead system assets through insurance, the General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets prior to the transfer to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations, and to date, no material environmental risks have been identified.

        In November 2007, an unexpected release and fire on line 3 of our Lakehead system occurred during planned maintenance near our Clearbrook, Minnesota terminal. We immediately shut down all pipelines in the vicinity and dispatched emergency response crews to oversee containment, cleanup and repair of the pipeline at an estimated economic cost of $2.6 million. Lines 1, 2 and 4 were restarted the following day after inspections revealed these lines had not been damaged. The volume of oil released was approximately 325 barrels, which was largely contained in the trench that had been excavated to facilitate the planned maintenance. We completed excavation and repairs and returned the line to service within 5 days. We continue to work with federal and state environmental and pipeline safety regulators to investigate the cause of the incident. We have the potential of incurring additional costs in connection with this incident, including expenditures necessary to remediate any operating condition that is determined to have caused this incident.

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        As of December 31, 2007 and 2006, we have recorded $3.4 million and $4.1 million in current liabilities and $2.8 million and $3.3 million, respectively, in long-term liabilities primarily to address remediation of asbestos containing materials, management of hazardous waste material disposal, and outstanding air quality measures for certain of our liquids and natural gas assets.

Oil and Gas in Custody

        Our Liquids assets transport crude oil and NGLs owned by our customers for a fee. The volume of liquid hydrocarbons in our pipeline systems at any one time varies from approximately 22 to 40 million barrels, virtually all of which is owned by our customers. Under the terms of our tariffs, losses of crude oil from identifiable incidents not resulting from our direct negligence may be apportioned among our customers. In addition, we maintain adequate property insurance coverage with respect to crude oil and NGLs in our custody.

        Approximately 50% of the natural gas volumes on our natural gas assets are transported for customers on a contractual basis. We purchase the remaining 50% and sell to third-parties downstream of the purchase point. At any point in time, the value of our customers' natural gas in the custody of our natural gas systems is not material to us.

Right-of-Way

        As part of our pipeline construction process, we must obtain certain right-of-way agreements from landowners whose property the pipeline will cross. Right-of-way agreements that we buy are capitalized as part of Property, plant and equipment. Right-of-way agreements that are leased from a third-party are expensed. We recorded expenses of $1.6 million, $2.1 million, and $1.9 million for the leased right-of-way agreements for the years ended December 31, 2007, 2006, and 2005, respectively.

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 that the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition.

Future Minimum Commitments

        As of December 31, 2007, our future minimum commitments that have remaining non-cancelable terms in excess of one year are as follows:

Future Minimum Commitments
   2008
   2009
   2010
   2011
   2012
   Thereafter
   Total
 
   (in millions)
Purchase commitments(1)   $ 305.4   $ —   $ —   $ —   $ —   $ —   $ 305.4
Power commitments(2)     2.9     0.2     0.2     —     —     —     3.3
Other operating leases     11.9     8.9     2.7     0.4     —     0.1     24.0
Right-of-way(3)     1.7     1.7     1.7     1.7     1.7     41.0     49.5
Product purchase obligations(4)     55.7     38.5     34.5     32.7     31.0     84.3     276.7
Service contract obligations(5)     36.0     28.8     25.6     18.6     7.3     0.5     116.8
   
 
 
 
 
 
 
Total   $ 413.6   $ 78.1   $ 64.7   $ 53.4   $ 40.0   $ 125.9   $ 775.7
   
 
 
 
 
 
 
(1)
Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our expansion projects.

(2)
Represents commitments to purchase power in connection with our Liquids segment.

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(3)
Right-of-way payments are estimated to be approximately $1.7 million per year for the remaining life of all pipeline systems, which has been assumed to be 25 years for purposes of calculating the amount of future minimum commitments beyond 2012.

(4)
We have long-term product purchase obligations with several third-party suppliers to acquire natural gas and NGLs at prices approximating market at the time of delivery.

(5)
The service contract obligations represent the minimum payment amounts for firm transportation and storage capacity we have reserved on third-party pipelines and storage facilities.

13. FINANCIAL INSTRUMENTS

Fair Value of Debt Obligations

        The table below presents the carrying amount and approximate fair values of our debt obligations. The carrying amounts of our commercial paper obligations approximate their fair values at December 31, 2007, due to the short-term nature of these obligations. The fair values of the First Mortgage Notes and Senior notes have been determined based on quotations of indicative pricing for which we could issue the same or similar securities quoted market prices for the same or similar issues.

 
   December 31, 2007
   December 31, 2006
 
   Carrying Amount
   Fair Value
   Carrying Amount
   Fair Value
 
   (in millions)
Commercial paper   $ 268.5   $ 268.5   $ 443.7   $ 443.7
Credit Facility     400.0     400.0     —     —
9.150% First Mortgage Notes     124.0     135.1     155.0     169.5
5.358% Senior unsecured zero coupon notes due 2022     203.6     210.7     —     —
4.000% Senior notes due 2009     200.0     198.5     200.0     194.2
7.900% Senior notes due 2012     99.9     110.2     99.9     110.5
4.750% Senior notes due 2013     199.8     192.0     199.8     188.6
5.350% Senior notes due 2014     199.9     194.3     199.9     193.0
5.875% Senior notes due 2016     299.7     293.7     299.7     297.4
7.000% Senior notes due 2018     99.9     105.3     99.8     107.9
7.125% Senior notes due 2028     99.8     104.3     99.8     108.9
5.950% Senior notes due 2033     199.7     176.9     199.7     186.2
6.300% Senior notes due 2034     99.8     92.1     99.8     97.1
8.050% Junior subordinated notes due 2067     399.3     385.9     —     —

Fair Value of Derivative Financial Instruments

        The fair values of our derivative financial instruments are determined based on available market information, valuation and modeling techniques. These modeling techniques require us to make estimates of future prices, price correlation, market volatility and liquidity. The estimates also reflect factors for time value of money and the volatility of prices underlying the contracts, the potential impact of liquidating positions in an orderly manner over a reasonable period of time under present market conditions, modeling risk, credit risk of counterparties and operational risk.

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Interest Rate Derivatives

        We enter into interest rate swaps, collars and derivative financial instruments with similar characteristics to manage the effect of future interest rate movements on our interest costs. The following table provides information about our current interest rate derivatives by transaction type for the specified periods.

 
    
    
    
    
   Fair Value at December 31,
  
 
    
   Partnership
    
  
 
   Notional
Principal
    
  
 
   Pays
   Receives
   Maturity Date
   2007
   2006
  
 
    
    
    
    
   (dollars in millions)

  
Interest Rate Swaps                                
  Floating to Fixed:                                
    $ 50.0   4.715%   LIBOR (2) January 22, 2007   $ —   $ 0.1  
    $ 50.0   4.738%   LIBOR   January 24, 2007     —     0.1  
    $ 50.0   4.740%   LIBOR   February 3, 2007     —     0.1  
    $ 50.0   4.750%   LIBOR   February 8, 2007     —     0.1  
    $ 50.0   5.158%   LIBOR   April 3, 2007     —     0.1  
    $ 50.0   5.163%   LIBOR   April 10, 2007     —     —  
    $ 50.0   5.165%   LIBOR   April 17, 2007     —     —  
    $ 50.0   5.175%   LIBOR   April 25, 2007     —     —  
    $ 50.0   4.6175%   LIBOR   January 15, 2009     (0.3 )   —  
    $ 50.0   4.6130%   LIBOR   January 29, 2009     (0.3 )   —  
    $ 50.0   4.6525%   LIBOR   February 13, 2009     (0.4 )   —  
    $ 50.0   4.5875%   LIBOR   February 20, 2009     (0.4 )   —  
    $ 50.0   4.370%   LIBOR-21bps   June 1, 2013     (0.7 )   1.5  
    $ 50.0   4.3425%   LIBOR-21bps   June 1, 2013     (0.6 )   1.6  
    $ 25.0   4.310%   LIBOR-25bps   June 1, 2013     (0.3 )   0.7  
  Fixed to Floating:                                
    $ 50.0   LIBOR-21bps (1) 4.750%   June 1, 2013     1.6     (0.5 )
    $ 50.0   LIBOR-21bps   4.750%   June 1, 2013     1.6     (0.5 )
    $ 25.0   LIBOR-25bps   4.750%   June 1, 2013     0.9     (0.3 )
Treasury Locks:                                
    $ 100.0   4.697%   30Yr UST (3) December 17, 2007     —     1.2  
    $ 100.0   4.668%   30Yr UST   December 17, 2007     —     1.6  
    $ 100.0   4.750%   30Yr UST   June 30, 2008     (4.4 )   —  
    $ 100.0   4.714%   30Yr UST   June 30, 2008     (3.9 )   —  
Interest Rate Collars:                                
    Calls   $ 50.0   5.500%   LIBOR   June 13, 2008     —     0.1  
    Puts   $ 50.0   4.199%   LIBOR   June 13, 2008     —     —  
    Calls   $ 50.0   5.500%   LIBOR   June 25, 2008     —     —  
    Puts   $ 50.0   4.149%   LIBOR   June 25, 2008     —     —  
(1)
A bps refers to a basis point. One basis point is equivalent to 1/100th of 1 percent.

(2)
LIBOR refers to the three-month U.S. London Interbank Offered Rate.

(3)
UST refers to United States Treasury notes.

        Our treasury locks and a portion of our interest rate collars maturing in 2008 qualify for hedge accounting treatment pursuant to the requirements of SFAS No. 133 and have been designated as cash flow hedges of future interest payments on the first $200 million of an anticipated debt issuance and interest payments on $50 million of our variable rate indebtedness, respectively. As such, the fair value of these derivative financial instruments is recorded as assets or liabilities on our consolidated statements of

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financial position with the changes in fair value recorded as corresponding increases or decreases in Accumulated Other Comprehensive Income, or AOCI. Our floating to fixed rate interest rate swaps and a portion of our interest rate collars maturing in 2008 and 2009 hedging $250 million of our variable rate indebtedness did not qualify for hedge accounting treatment as set forth in SFAS No. 133 at December 31, 2007. As such, changes in the fair value of these derivative financial instruments are recorded in earnings as an increase or decrease in interest expense. A portion of these transactions have subsequently been re-designated as cash flow hedges of forecast floating rate indebtedness.

        The floating to fixed rate and fixed to floating rate interest rate swaps maturing in 2013 have not been designated as cash flow or fair value hedges under SFAS No. 133 and, as a result, changes in the fair value of these derivative financial instruments are recorded in earnings as an increase or decrease in interest expense.

Commodity Price Derivatives

        The following table provides summarized information about the fair values of our outstanding commodity derivative financial instruments at December 31, 2007 and 2006:

 
   December 31, 2007
   December 31, 2006
  
 
    
   Wtd Avg Price
   Fair Value(3)
   Fair Value(3)
  
 
   Notional
   Receive
   Pay
   Asset
   Liability
   Asset
   Liability
  
Swaps                                          
  Natural gas(1)                                          
    Receive variable/ pay fixed   53,477,203   $ 7.43   $ 7.31   $ 21.6   $ (16.1 ) $ 25.6   $ (94.2 )
    Receive fixed/ pay variable   67,237,786     5.59     8.00     11.5     (160.5 )   84.3     (160.7 )
    Receive variable/ pay variable   208,270,399     7.87     7.84     11.5     (6.0 )   7.9     (4.8 )
  NGL(2)                                          
    Receive variable/ pay fixed   —     —     —     —     —     —     (0.5 )
    Receive fixed/ pay variable   10,163,878     42.19     58.68     —     (160.6 )   18.3     (34.4 )
  Crude(2)                                          
    Receive fixed/ pay variable   1,411,221     62.27     88.36     —     (34.6 )   0.2     (18.5 )
Options—calls                                          
  Natural gas(1)   1,461,000     4.31     8.36     —     (5.6 )   —     (5.4 )
Options—puts                                          
  Natural gas(1)   1,401,000     8.41     3.40     —     —     1.0     —  
  NGL(2)   763,403     61.42     43.54     0.7     —     —     —  
                   
 
 
 
 
Totals(4)                   $ 45.3   $ (383.4 ) $ 137.3   $ (318.5 )
                   
 
 
 
 
(1)
Notional amounts for natural gas are recorded in millions of British thermal units ("MMBtu").

(2)
Notional amounts for NGL and Crude are recorded in Barrels ("Bbl").

(3)
Fair values of derivatives are presented in millions of dollars.

(4)
We record the fair value of our derivative financial instruments in the balance sheet as current and long-term assets or liabilities on a net basis by counterparty.

14. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

        Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins (the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases). Our interest rate risk exposure does not exist within any of our segments, but exists at the corporate level where our variable rate debt obligations are issued. Our exposure to commodity price risk exists within our Natural Gas and Marketing segments. We use derivative

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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, as well as reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.

Accounting Treatment

        We record all derivative financial instruments in our consolidated financial statements at fair market value which we adjust each period for changes in the fair market value ("mark-to-market"). The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay or receive, other than in a forced or liquidation sale, to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We use actively traded external market quotes and indices to value substantially all of the derivative financial instruments we utilize.

        Under the guidance of SFAS No. 133, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is adjusted to its fair market value, or marked-to-market, each period with the increases and decreases in fair value recorded in our consolidated statements of income as increases and decreases in Cost of natural gas for our commodity-based derivatives and Interest expense for our interest rate derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

        If a derivative financial instrument qualifies and is designated as a cash flow hedge, a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in Accumulated other comprehensive income ("AOCI"), a component of Partners' Capital, until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge's change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in Cost of natural gas for commodity hedges and Interest expense for interest rate hedges in the period the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued, remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible, to mitigate the non-cash earnings volatility that arises from recording the changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting as set forth in SFAS No. 133, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

        If a derivative financial instrument is designated and qualifies as a hedge of the change in fair market value of an underlying asset or liability, the gain or loss resulting from the change in fair market value of the derivative financial instrument is recorded in earnings adjusted by the gain or loss resulting from the change in fair market value of the underlying asset or liability. Any ineffective portion of a fair value hedge's change in fair market value will be recorded in earnings as the amount that is not offset by the gain or loss on the change in fair market value of the underlying asset or liability. We include the gains and losses associated with derivative financial instruments designated and qualifying as fair value hedges of our

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debt obligations in Interest expense on our consolidated statements of income. Similar to derivative financial instruments designated as cash flow hedges, to qualify as a fair value hedge very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Non-Qualified Hedges

        Many of our derivative financial instruments qualify for hedge accounting treatment under the specific requirements of SFAS No. 133. However, we have four primary transaction types associated with our commodity derivative financial instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting under SFAS No. 133 and are referred to as "non-qualified." These non-qualified derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in cost of natural gas in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.

        The four primary transaction types that do not qualify for hedge accounting are as follows:

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        In each of the instances described above, the underlying physical purchase, storage and sale of natural gas and NGLs are accounted for on a historical cost or market basis rather than on the mark-to-market basis we utilize for the derivative financial instruments employed to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at historical cost) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated.

        We routinely enter into interest rate swaps to fix the interest rates associated with our variable rate debt, including commercial paper and bank borrowings. In August 2007, we entered into forward-starting interest rate swaps that we designated as cash flow hedges of variable rate debt to begin in October 2007 and November 2007. The specific floating rate borrowings did not take place as initially forecast, thereby causing the interest rates swaps to no longer qualify as cash flow hedges. As a result, we recorded a charge to interest expense of $1.4 million, representing the fair market value of the interest rate swaps at December 31, 2007. A portion of these transactions have subsequently been re-designated as cash flow hedges of forecast floating rate indebtedness.

Discontinuance of Hedge Accounting

        In 2005, we discontinued application of hedge accounting in connection with some of our derivative financial instruments designated as hedges of forecasted sales and purchases of natural gas. We discontinued application of hedge accounting when we determined it was no longer probable that the originally forecasted purchases and sales of natural gas would occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. As discussed above, this can occur because we have the flexibility to make changes to the underlying delivery locations for our transportation assets and to the underlying injection or withdrawal schedule for our storage assets, given changes in market conditions. One of the key criteria to achieve hedge accounting under SFAS No. 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, in 2005, we recognized previously deferred unrealized losses in our Marketing segment of approximately $9.0 million from the discontinuance of hedge accounting. In doing so, we reclassified the $9.0 million to cost of natural gas on our consolidated statements of income from AOCI. Going forward, the derivative financial instruments for which hedge accounting has been discontinued are considered to

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be non-qualified under SFAS No. 133, and must be marked-to-market each period, with the increases and decreases in fair value recorded as increases and decreases in earnings. Also included in the loss from discontinuance are approximately $2.1 million of net mark-to-market losses that relate to hedge positions that were closed out in 2005.

        The following table presents the unrealized gains and losses associated with changes in the fair value of our derivatives, which are recorded as an element of cost of natural gas and interest expense in our consolidated statements of income and disclosed as a reconciling item on our consolidated statements of cash flows:

Derivative fair value gains (losses)
   December 31,
2007
   December 31,
2006
   December 31,
2005
  
 
   (in millions)

  
Natural Gas segment                    
  Hedge ineffectiveness   $ —   $ (1.9 ) $ (2.5 )
  Non-qualified hedges     (59.0 )   1.8     (5.6 )
Marketing                    
Non-qualified hedges     (3.8 )   64.5     (41.3 )
  Discontinued hedges     —     —     (9.0 )
   
 
 
 
    Commodity derivative fair value gains (losses)     (62.8 )   64.4     (58.4 )
Corporate                    
  Non-qualified interest rate hedges     (1.4 )   —     —  
   
 
 
 
Derivative fair value gains (losses)   $ (64.2 ) $ 64.4   $ (58.4 )
   
 
 
 

De-designation and Settlement of Derivatives

        In connection with the sale of assets in December 2005, as discussed in Note 3 to these consolidated financial statements, we settled for cash of approximately $16.3 million, natural gas collars representing derivative financial instruments on sales of 2,000 MMBtu/d of natural gas through 2011. We had previously recorded unrealized losses associated with the natural gas collars that were realized upon settlement. Additionally, we de-designated derivative financial instruments that qualified for and were designated as cash flow hedges of forecasted sales of 273 Bpd of NGLs through 2007 and contemporaneously closed out the position by entering into an offsetting derivative financial instrument, at market, on forecasted purchases of 273 Bpd of NGLs through 2007.

Derivative Positions

        Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:

 
   December 31,
2007
   December 31,
2006
  
 
   (in millions)

  
Other current assets   $ 6.5   $ 7.2  
Other assets, net     6.4     11.0  
Accounts payable and other     (165.5 )   (57.2 )
Other long-term liabilities     (192.9 )   (136.4 )
   
 
 
    $ (345.5 ) $ (175.4 )
   
 
 

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        The increase in our obligation associated with derivative activities is primarily due to the increase in current and forward natural gas and NGL prices from December 31, 2006 to December 31, 2007. Our portfolio of derivative financial instruments is largely comprised of long-term fixed price natural gas and NGL sales and purchase agreements.

        We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. We regularly enter into treasury locks to hedge the interest on anticipated issuances of indebtedness. The settlement of a treasury lock can result in the retention of unrecognized gains or losses in AOCI that are amortized to interest expense over the life of the related debt issuance. In connection with our 2007 issuance and sale of $400 million in principal amount of our Junior Notes, we paid $0.9 million to settle treasury locks we entered to hedge the first five years of interest payments on a portion of this obligation. The $0.9 million is being amortized from AOCI to interest expense over the five year period for which the derivative instrument was established to hedge of interest payments on the junior notes. In December 2006, we paid $10.2 million to settle treasury locks we entered to hedge a portion of the interest payments associated with our issuance of $300 million in principal amount of our senior notes. The $10.2 million is being amortized from AOCI to interest expense over the 10-year life of the senior notes.

        Also included in AOCI are unrecognized losses of approximately $2.0 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted commodity transactions that were subsequently de-designated. These unrealized losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. For the years ended December 31, 2007, 2006 and 2005, we reclassified unrealized losses of $94.8 million, $78.3 million and $33.8 million, respectively, from AOCI to cost of natural gas on our consolidated statements of income for the fair value of derivative financial instruments that were settled. We estimate that approximately $113 million of AOCI representing unrealized net losses on cash flow hedging activities at December 31, 2007, will be reclassified to earnings during the next twelve months.

        We do not require collateral or other security from the counterparties to our derivative financial instruments, all of which were rated "BBB+" or better by the major credit rating agencies.

15. INCOME TAXES

        We are not a taxable entity for U.S. federal income tax purposes, or for the majority of states that impose an income tax. These taxes on our net income are generally borne by our unitholders through the allocation of taxable income. Beginning in 2006, two states enacted substantial changes to their tax structures to impose taxes that are based upon many but not all items included in net income. We report these taxes as income taxes under the provisions of Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS No. 109").

        Our income tax expense is $5.1 million for the year ended December 31, 2007, which we computed by applying a 0.57% state income tax rate to modified gross revenue. Our income tax expense represents a 2.0% effective rate as applied to pretax book income. At December 31, 2007 we have included a current income tax payable of $4.9 million in property and other taxes payable. In addition, we have included a deferred income tax asset of $0.6 million in other assets, net on our consolidated statement of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

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        We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. The impact of changes in tax legislation on deferred income tax liabilities and assets is recorded in the period of enactment. The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:

Net book basis of assets in excess of tax basis   $ (1.3 )
Net book losses on derivatives not recognized for tax purposes     1.9  
   
 
Net deferred tax asset   $ 0.6  
   
 

Accounting for Uncertainty in Income Taxes

        In July 2006, the Financial Accounting Standards Board ("FASB") issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement 109, or FIN 48. This Interpretation clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes. We implemented FIN 48 during the first quarter of 2007. Our adoption of FIN 48 did not materially affect our operating results, financial position or cash flows. As of December 31, 2007, we have no liability reported for unrecognized tax benefits.

        Our tax years are generally open to examination by the Internal Revenue Service and state revenue authorities for calendar years ending December 2006, 2005, and 2004.

16. SEGMENT INFORMATION

        Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker in deciding how resources are allocated and performance is assessed.

        Each of our reportable segments is a business unit that offers different services and products that is managed separately, since each business segment requires different operating strategies. We have segregated our business activities into three distinct operating segments:

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        The following table presents certain financial information relating to our business segments as of and for the years ended December 31, 2007, 2006 and 2005.

 
   As of and for the Year Ended December 31, 2007
 
   Liquids
   Natural Gas
   Marketing
   Corporate(1)
   Total
 
   (in millions)
Total revenue   $ 548.1   $ 5,807.3   $ 3,527.5   $ —   $ 9,882.9
Less: Intersegment revenue     —     2,363.3     237.0     —     2,600.3
   
 
 
 
 
Operating revenue     548.1     3,444.0     3,290.5     —     7,282.6
Cost of natural gas     —     2,990.0     3,256.9     —     6,246.9
Operating and administrative     156.1     266.7     8.0     3.5     434.3
Power     117.0     —     —     —     117.0
Depreciation and amortization     67.9     96.1     1.6     —     165.6
   
 
 
 
 
Operating income     207.1     91.2     24.0     (3.5 )   318.8
Interest expense     —     —     —     99.8     99.8
Other income     —     —     —     3.0     3.0
   
 
 
 
 
Income from continuing operations before income tax expense     207.1     91.2     24.0     (100.3 )   222.0
Income tax expense     —     —     —     5.1     5.1
   
 
 
 
 
Income from continuing operations     207.1     91.2     24.0     (105.4 )   216.9
Income from discontinued operations     —     32.6     —     —     32.6
   
 
 
 
 
  Net income   $ 207.1   $ 123.8   $ 24.0   $ (105.4 ) $ 249.5
   
 
 
 
 
Total assets   $ 2,976.9   $ 3,461.1   $ 349.6   $ 104.0   $ 6,891.6
   
 
 
 
 
Capital expenditures (excluding acquisitions)   $ 1,218.8   $ 747.9   $ 1.6   $ 11.9   $ 1,980.2
   
 
 
 
 
(1)
Corporate consists of interest expense, interest income and other costs such as certain taxes, which are not allocated to the other business segments.

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   As of and for the Year Ended December 31, 2006
 
   Liquids
   Natural Gas
   Marketing
   Corporate(1)
   Total
 
   (in millions)
Total revenue   $ 512.8   $ 5,404.1   $ 3,182.3   $ —   $ 9,099.2
Less: Intersegment revenue     —     2,383.4     206.8     —     2,590.2
   
 
 
 
 
Operating revenue     512.8     3,020.7     2,975.5     —     6,509.0
Cost of natural gas     —     2,601.1     2,913.5     —     5,514.6
Operating and administrative     141.3     215.4     5.4     2.7     364.8
Power     107.6     —     —     —     107.6
Depreciation and amortization     64.1     70.3     0.5     0.2     135.1
   
 
 
 
 
Operating income     199.8     133.9     56.1     (2.9 )   386.9
Interest expense     —     —     —     110.5     110.5
Other income     —     —     —     8.5     8.5
   
 
 
 
 
Income from continuing operations before income taxes     199.8     133.9     56.1     (104.9 )   284.9
Income tax expense     —     —     —     —     —
   
 
 
 
 
Income from continuing operations     199.8     133.9     56.1     (104.9 )   284.9
Income from discontinued operations     —     —     —     —     —
   
 
 
 
 
  Net income   $ 199.8   $ 133.9   $ 56.1   $ (104.9 ) $ 284.9
   
 
 
 
 
Total assets   $ 1,816.4   $ 2,797.3   $ 366.9   $ 243.2   $ 5,223.8
   
 
 
 
 
Capital expenditures (excluding acquisitions)   $ 237.2   $ 614.8   $ 1.9   $ 10.5   $ 864.4
   
 
 
 
 
(1)
Corporate consists of interest expense, interest income and other costs such as certain taxes, which are not allocated to the other business segments.

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   As of and for the Year Ended December 31, 2005
  
 
   Liquids
   Natural Gas
   Marketing
   Corporate(1)
   Total
  
 
   (in millions)

  
Total revenue   $ 418.0   $ 4,945.1   $ 3,884.2   $ —   $ 9,247.3  
Less: Intersegment revenue     —     2,593.0     177.4     —     2,770.4  
   
 
 
 
 
 
Operating revenue     418.0     2,352.1     3,706.8     —     6,476.9  
Cost of natural gas     —     2,018.7     3,744.6     —     5,763.3  
Operating and administrative     144.2     175.0     4.1     3.5     326.8  
Power     74.8     —     —     —     74.8  
Depreciation and amortization     71.7     66.0     0.5     —     138.2  
Gain on sale of assets     —     (18.1 )   —     —     (18.1 )
   
 
 
 
 
 
Operating income     127.3     110.5     (42.4 )   (3.5 )   191.9  
Interest expense     —     —     —     107.7     107.7  
Other income     —     —     —     5.0     5.0  
   
 
 
 
 
 
Income from continuing operations before income taxes     127.3     110.5     (42.4 )   (106.2 )   89.2  
Income tax expense     —     —     —     —     —  
   
 
 
 
 
 
Income from continuing operations     127.3     110.5                    
Income from discontinued operations     —     —     —     —     —  
   
 
 
 
 
 
  Net income   $ 127.3   $ 110.5   $ (42.4 ) $ (106.2 ) $ 89.2  
   
 
 
 
 
 
Total assets   $ 1,664.0   $ 2,145.9   $ 512.3   $ 106.2   $ 4,428.4  
   
 
 
 
 
 
Capital expenditures (excluding acquisitions)   $ 77.0   $ 263.8   $ 0.2   $ 3.8   $ 344.8  
   
 
 
 
 
 
(1)
Corporate consists of interest expense, interest income and other costs such as certain taxes, which are not allocated to the other business segments.

17. SUBSEQUENT EVENTS

        On January 28, 2008, the board of directors of Enbridge Management declared a distribution payable to our partners on February 14, 2008. The distribution was paid to unitholders of record as of February 6, 2008, of our available cash of $96.7 million at December 31, 2007, or $0.950 per limited partner unit. Of this distribution, $66.0 million was paid in cash, $12.9 million was distributed in i-units to our i-unitholder, $17.2 million was distributed in Class C units to the holders of our Class C units and $0.6 million was retained from the General Partner in respect of the i-unit and Class C unit distributions to maintain its two percent general partner interest.

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18. QUARTERLY FINANCIAL DATA (Unaudited)

 
   First
   Second
   Third
   Fourth
   Total
 
   (in millions, except per unit amounts)
2007 Quarters                              
Operating revenue   $ 1,712.7   $ 1,738.7   $ 1,710.9   $ 2,120.3   $ 7,282.6
Operating income   $ 64.1   $ 90.9   $ 101.6   $ 62.2   $ 318.8
Income from continuing operations   $ 39.1   $ 68.6   $ 77.3   $ 31.9   $ 216.9
Income from discontinued operations   $ —   $ —   $ —   $ 32.6   $ 32.6
Net income   $ 39.1   $ 68.6   $ 77.3   $ 64.5   $ 249.5
Net income per limited partner unit(1)   $ 0.40   $ 0.69   $ 0.75   $ 0.59   $ 2.45
2006 Quarters                              
Operating revenue   $ 1,888.6   $ 1,424.7   $ 1,532.3   $ 1,663.4   $ 6,509.0
Operating income(2)   $ 108.0   $ 93.6   $ 108.7   $ 76.6   $ 386.9
Net income(2)   $ 81.1   $ 70.4   $ 82.2   $ 51.2   $ 284.9
Net income per limited partner unit(1)(2)   $ 1.12   $ 0.96   $ 1.03   $ 0.56   $ 3.62
(1)
The General Partner's allocation of net income has been deducted before calculating net income per limited partner unit.

(2)
The fourth quarter of 2006 includes approximately $8.3 million for raw natural gas purchases and transportation and fractionation charges that relate to prior years that we had not previously recorded.

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