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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

Commission File Number: 1-10934

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

        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. o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act) Yes ý    No o

        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, 2003, was $1,683,394,439.

        DOCUMENTS INCORPORATED BY REFERENCE: NONE

TABLE OF CONTENTS

        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 the ability of the Partnership to control or predict. For additional discussion of risks, uncertainties and assumptions, see "Items 1. & 2. Business and Properties—Risk Factors" included elsewhere in this Form 10-K.

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Glossary

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

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PART I

Items 1. & 2.—Business & Properties

OVERVIEW

        The Partnership is a publicly traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation assets and natural gas gathering, treating, processing, transmission and marketing assets in the United States. The Class A common units of the Partnership are traded on the NYSE under the symbol "EEP."

        The Partnership was formed in 1991 by the 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. Since the Partnership's initial public offering in 1991, it has increased its quarterly cash distribution by 57% from $0.59 per unit to the current quarterly rate of $0.925 per unit.

        The Partnership's ownership is comprised of a 2% general partner interest and a 98% limited partner interest. The General Partner owns the 2% general partner interest and a 7.1% limited partner interest, in the form of 3,912,750 Class B common units in the Partnership. The remaining 90.9% limited partner interest is represented by a 72.7% ownership interest of 40,166,134 publicly traded Class A common units and an 18.2% ownership interest of 10,062,170 i-units, which are wholly-owned by Enbridge Management.

        Enbridge Management is a Delaware limited liability company that was formed on May 14, 2002. Enbridge Management's shares represent limited liability company interests and are traded on the NYSE under the symbol "EEQ." Its principal asset is its 18.2% limited partnership interest in the Partnership through its ownership of i-units. Enbridge Management's principal activity is managing the business and affairs of the Partnership and its subsidiaries. Under a Delegation of Control Agreement, the General Partner delegated substantially all of its power and authority to manage the business and affairs of the Partnership to Enbridge Management. The General Partner, through its direct ownership of the voting shares of Enbridge Management, elects all of the directors of Enbridge Management.

        Since May 2001, the Partnership has diversified its operations both geographically and by industry. The North Dakota system, acquired in May 2001, connects to the Partnership's Lakehead system and accessed a different crude oil supply basin in North Dakota and Montana. The East Texas system, acquired in November 2001, was the Partnership's first entry into the natural gas gathering and processing business and diversified the geographic focus of the Partnership to include the southern United States. In October 2002, the Partnership continued its diversification through the acquisition of the Midcoast system, which included natural gas gathering, treating, processing, transmission and marketing activities located in the southern United States. On December 31, 2003, the Partnership acquired the North Texas system, a natural gas gathering and processing business in Texas.

AVAILABLE INFORMATION

        The Partnership files annual, quarterly and other reports and information with the SEC under the Exchange Act. You may read and copy any materials that the Partnership files with the SEC at the SEC's Public Reference Room at 450 Fifth Street, NW, 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 the Partnership.

        The Partnership also makes available free of charge on or through its Internet website http://www.enbridgepartners.com its 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

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those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after the Partnership electronically files such material with the SEC.

BUSINESS STRATEGY

        The primary strategy of the Partnership is to grow cash distributions through the profitable expansion of existing assets and through the development and acquisition of complementary businesses with risk profiles similar to the Partnership's current business.

        A number of developments in 2003 strengthened the Partnership's position as a crude oil carrier into the U.S. Mid-Continent. The Partnership continues to expand the Lakehead system's capacity through the construction of Terrace and the complementary expansion of pipeline facilities in the Chicago area. CAPP had requested these expansions, in anticipation of future growth in crude oil production from the prolific Alberta oil sands. In September 2003, Enbridge purchased a crude oil pipeline that currently flows from Cushing, Oklahoma to Chicago, Illinois. Enbridge intends to reverse the direction of flow on this system, which should ultimately increase market access for Canadian crude oil delivered on the Lakehead system. In December 2003, the Partnership announced the acquisition of crude oil pipeline and storage facilities in the U.S. Mid-Continent, which closed in the first quarter of 2004. This acquisition is expected to be accretive to cash distributions while, at the same time, increasing the diversity of sources of crude oil, thereby reducing the Partnership's dependence on western Canadian crude oil volumes.

        The Partnership continues to grow its natural gas business with the acquisition of the North Texas gathering and processing system on December 31, 2003, adding to its presence in Texas. Effective October 2003, the Partnership made a decision to proceed with the construction of a pipeline to connect its East Texas system to the Carthage, Texas hub. Carthage access is important to shippers because it offers a number of connections to interstate natural gas pipelines. These projects are allowing the Partnership to achieve a larger scale and geographic profile from its East Texas system to its Anadarko system in the Texas panhandle, where it can pursue commercial and operating synergies that will make it the operator of choice in Texas.

        The Partnership will continue to analyze potential acquisitions, with a focus on crude oil, refined products and natural gas pipelines, terminals and related facilities. Major energy companies have sold their non-strategic assets in recent years, continuing the trend of rationalization of the energy infrastructure in the United States. The Partnership expects this trend to continue and believes it is well positioned to participate in these opportunities. The Partnership will seek out opportunities throughout the United States, particularly in the U.S. Gulf Coast area, where asset divestitures are anticipated in and around its existing natural gas gathering, processing and transportation businesses.

BUSINESS SEGMENTS

        The Partnership conducts its business through four business segments: Liquids Transportation, Gathering and Processing, Natural Gas Transportation and Marketing.

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Liquids Transportation includes the operations of a common carrier pipeline and a feeder pipeline, which transport crude oil and other liquid hydrocarbons.



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Gathering and Processing consists of natural gas gathering pipelines, treating plants and processing plants. This segment also includes the transportation of natural gas liquids, crude oil and carbon dioxide by rail and road.



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Natural Gas Transportation includes the operations of natural gas transmission pipeline systems.



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The Marketing segment provides natural gas supply, transmission and sales services for customers.

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Liquid Transportation Segment

Lakehead system

        The Lakehead system in the United States and the Enbridge system in Canada, which is owned by Enbridge Pipelines, a wholly-owned subsidiary of Enbridge, together form the System. The System, which spans 3,100 miles, is the longest liquid petroleum pipeline system in the world and transports crude oil and other liquid petroleum products as a common carrier. The System is the primary transporter of crude oil from western Canada to the United States and the only pipeline that transports crude oil from western Canada to the province of Ontario in eastern Canada.

        The System serves all the major refining centers in the Great Lakes and upper Midwest regions of the United States and the province of Ontario, and, through interconnects, the Patoka/Wood River pipeline hub located in southern Illinois. Deliveries of crude oil and NGLs from the Lakehead system are made principally to refineries, either directly or through connecting pipelines of other companies, and serve as feedstocks for refineries and petrochemical plants.

        The Lakehead system is a FERC regulated interstate common carrier pipeline system. The Lakehead system spans approximately 1,900 miles, and consists of approximately 3,300 miles of pipe with diameters ranging from 12 inches to 48 inches, 59 pump station locations with a total of approximately 752,000 installed horsepower and 60 crude oil storage tanks with an aggregate working capacity of approximately 14 million barrels. The System operates in a segregation, or batch mode. This operating mode allows the Lakehead system to transport up to 45 different types of liquid hydrocarbons including light, medium and heavy crude oil (including bitumen, which is a naturally occurring tar-like mixture of hydrocarbons), condensate and NGLs. This flexibility increases utilization of the system and enhances the Partnership's ability to serve its customers.

        Customers.    The Lakehead system operates under month-to-month transportation arrangements with its shippers. During 2003, 36 shippers tendered crude oil and liquid petroleum for delivery through the Lakehead system. These customers include integrated oil companies, major independent oil producers, refiners and marketers.

        Supply and Demand.    The Lakehead system is well positioned as the primary transporter of western Canadian crude oil and will benefit from the growing production of crude oil from the Alberta oil sands. As with U.S. domestic conventional crude oil production, western Canada's conventional crude oil production is in decline. More than offsetting this decline is substantial growth in production from Canada's prolific oil sands resource from the WCSB.

        The western Canadian oil sands are naturally occurring mixtures of sand, water, clay, and approximately 12% bitumen. According to the Alberta Energy and Utilities Board, using existing technology, knowledge and economics, the remaining recoverable bitumen reserves in the province of Alberta were estimated at the end of 2002 at approximately 174 billion barrels. This represents a recovery of approximately 10% of the initial volume in place (over 1.6 trillion barrels). The cumulative production of bitumen to the end of 2002 stood at approximately 3.8 billion barrels. According to industry sources, the economics of producing bitumen have improved substantially from the late 1970's when average production costs were nearly $23 per barrel (including extraction and upgrading costs). Bitumen production must be blended with lighter, less viscous materials to permit transportation via pipelines to refinery markets. Alternatively, bitumen can be upgraded into a synthetic crude oil to meet the demand from a greater number of refineries. Recent industry estimates of the cost of producing upgraded crude oil from the bitumen deposits are $7 to $10 per barrel.

        Firms involved in the development of heavy crude oil from the Alberta oil sands have invested approximately $20.0 billion since 1995, with additional previously announced extraction or up-grader projects valued in excess of approximately $30.0 billion over the next ten years. This could provide up to 1.5 million bpd of incremental crude oil production from western Canada. Based upon Enbridge's

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survey of producers, refiners and governments conducted in early 2003, the supply of western Canadian crude oil and liquid petroleum is expected to be approximately 2.3 million bpd in 2004, 2.5 million bpd in 2005 and approximately 2.8 million bpd in 2010.

        Although substantially all of the crude oil and liquid petroleum delivered through the Lakehead system originates in oilfields in western Canada, the Lakehead system also receives approximately 5% of its receipts from domestic sources including:

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U.S. and Canadian production at Clearbrook, Minnesota through a connection with the North Dakota system;



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U.S. production at Lewiston, Michigan; and



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both U.S. and offshore production in the Chicago area.

        Supply from the WCSB, and hence future deliveries on the Lakehead system, is expected to grow over 2003 levels. The near-term growth in supply comes from the completion of the Syncrude and Suncor oil sands expansions and full year production from the AOSP and Cold Lake expansions. Syncrude and Suncor were the original oil sands producers in northern Alberta, and AOSP and Cold Lake expansions are separate producers and producing areas.

        During the fourth quarter of 2003, Syncrude announced the completion of the second mining train at its Aurora Mining site, which increases the bitumen mining capacity of the Syncrude project in preparation for its Aurora Upgrader Expansion project. With the completion of this project, Syncrude's synthetic crude oil production capacity is expected to grow to approximately 350,000 bpd by 2005-2006 from approximately 230,000 bpd in 2002.

        Suncor began upgrading bitumen from the first phase of its Firebag in-situ oil sands development near the end of 2003. Firebag phase one is expected to reach full production capacity of 35,000 bpd of bitumen production in mid-2005. When complete, the first phase of Firebag and expanded upgrader facilities are expected to bring Suncor's production capacity to 260,000 bpd in 2005, compared with 205,000 bpd in 2002.

        The AOSP, owned by Shell Canada Limited (60%), Chevron Canada Limited (20%) and Western Oil Sands L.P. (20%) began commercial operation in June 2003. AOSP consists of oil sands mining and bitumen extraction operations in the Fort McMurray, Alberta region with transportation to the Fort Saskatchewan, Alberta area for upgrading to sweet and heavy synthetic crude oil products. Production from this operation averaged 122,500 bpd during initial operations in 2003. The project has a design capacity to process 155,000 of bpd bitumen.

        Imperial Oil Limited recently completed certain phases of its Cold Lake expansion project. This project is expected to increase overall WCSB bitumen production by 30,000 bpd in 2004.

        Based on the above noted oil sands activity and its most recent survey of crude oil shippers, the Partnership estimates that deliveries on the Lakehead system will average approximately 1.45 million bpd in 2004, an increase of approximately 100,000 bpd over 2003. The Partnership further believes that the outlook for increased crude oil production in western Canada continues to be positive and will yield additional volumes. In that event, the Partnership should expect increased earnings contributions from the Lakehead system. As an example, an incremental 100,000 bpd of deliveries on the Lakehead system to Chicago would increase operating income by approximately $10.0 million. The Partnership expects that increased capacity utilization on the Lakehead system should support a significant component of its future earnings growth. The timing of growth in the supply of western Canadian crude oil will depend upon the level of crude oil prices, oil drilling activity, the development of the oil sands resource, and access to compatible markets for Canadian oil sands production.

        The Partnership's ability to increase deliveries and to expand its Lakehead system in the future will ultimately depend upon numerous factors. The investment levels and related development activities by

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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. 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, the System.

        The Partnership forecasts that demand for WCSB production will continue to increase in PADD II, which is the U.S. Government's designation for the area that includes the Great Lakes and Midwest regions of the United States. PADD II refinery configurations and crude oil requirements continue to be an attractive market for western Canadian supply. According to the U.S. Department of Energy's Energy Information Administration, demand for crude oil in PADD II increased from approximately 2.75 million bpd in 1984 to approximately 3.2 million bpd in 2002. Over that same period, production of crude oil within PADD II decreased from over 1.0 million bpd to approximately 450,000 bpd. The Partnership expects this gap between PADD II demand and production will continue to widen, contributing to increased demand for imports of crude oil to PADD II.

        The closure of Petro-Canada's Oakville, Ontario refinery in late 2004, is expected to result in a decline in the volume of crude oil delivered by the Lakehead system to the province of Ontario and a corresponding increase in deliveries into the PADD II market. Following the announced refinery closure, Lakehead system deliveries into Ontario are expected to remain relatively constant.

        In anticipation of improving supply and demand fundamentals, a major expansion of the System was commenced in 1999. This expansion, referred to as the Terrace expansion program, was undertaken at the request of CAPP and consists of a multi-phase expansion of both the Canadian and U.S. portions of the System. With the completion of the Terrace expansion program, as discussed below, approximately 350,000 bpd of incremental capacity has been added to the System.

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Phase I of the Terrace expansion program was completed in 1999 and included construction of a new 36-inch diameter pipeline facility from Kerrobert, Saskatchewan to Clearbrook, Minnesota that added approximately 170,000 bpd of capacity to the System. The Partnership's share of the cost of Phase I was approximately $140.0 million.



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Phase II of the Terrace expansion program was completed in early 2002. Although Phase II did not involve construction on the Lakehead system, the approximate 40,000 bpd increase in capacity of the Enbridge system is expected to benefit the Partnership directly by accommodating additional deliveries on the Lakehead system from the Alberta oil sands.



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Phase III of the Terrace expansion program was substantially complete in early 2003 and is designed primarily to increase heavy crude oil transportation capacity on the Lakehead system between Clearbrook and Superior, Wisconsin by approximately 140,000 bpd. The Partnership's cost of Phase III was approximately $195.0 million.



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Following Phase III of the Terrace expansion program, CAPP has also requested, and the Partnership has undertaken, the expansion of pipeline capacity into the Chicago market. Construction of additional facilities is underway and expected to be in service in 2004. The Partnership's cost is expected to be approximately $80.0 million.

        Competition.    As pipelines are the lowest cost method for intermediate and long haul movement of crude oil over land, the most significant existing competitors for the transportation of western Canadian crude oil are other pipelines. In 2003, the Enbridge system transported approximately 67% of total western Canadian crude oil production; the remainder was either refined in the provinces of Alberta, British Columbia or Saskatchewan, Canada or transported through other pipelines. Of the pipelines transporting western Canadian crude oil out of Canada, the System provides approximately 77% of the total pipeline design capacity. The remaining 23% is shared among five other pipelines

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transporting crude oil to British Columbia, Washington, Montana and other states in the northwestern United States.

        To address growing demand in the PADD IV and Puget Sound Area of PADD V, several expansions of these competing pipeline systems have been announced. Competing pipelines are owned by Terasen Inc. and transport crude oil from Alberta to British Columbia and Washington State through the Trans Mountain pipeline and from Alberta to the PADD IV region of the U.S. through the Express pipeline.

        Terasen Inc. has stated that it plans to apply to the NEB for approval to increase the capacity of its Trans Mountain pipeline from approximately 188,100 bpd to 214,500 bpd. It is anticipated that this expansion will be in service during the third quarter of 2004.

        Terasen Inc. has also announced plans to proceed with the expansion of the Express pipeline system from current capacity of 172,000 bpd to 280,000 bpd. Terasen Inc. expects this expansion to be in service by April 2005.

        Another competitor, Inter Pipeline Fund, has announced a commercial agreement with four shippers to increase southbound capacity on its Bow River pipeline by 17,000 bpd. This system transports western Canadian crude to markets in Montana. Inter Pipeline Fund expects the new facilities will be in place by May 1, 2004.

        The pipeline expansions into PADD IV are in line with management expectations as the PADD IV region indigenous supply continues to decline. Management expects the growing supply from Western Canada to substantially exceed the impact requirements of the PADD IV region, leaving the balance to be transported on the Lakehead system.

        In the United States, the Lakehead system encounters competition from other liquid petroleum pipelines and other modes of transportation delivering crude oil and refined products to the refining centers of Minneapolis-St. Paul, Minnesota; Superior, Wisconsin; Chicago, Illinois; Detroit, Michigan; Toledo, Ohio; and the Patoka/Wood River area in southern Illinois.

        The following table sets forth Lakehead system average deliveries per day and barrel miles for each of the five-year periods ended December 31, 2003.

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North Dakota system

        The North Dakota system is a crude oil gathering and transportation system servicing the Williston Basin in North Dakota and Montana. The North Dakota system's crude oil gathering pipelines collect crude oil from points near producing wells in approximately 36 oil fields in North Dakota and Montana and receive Canadian crude oil via an interconnect with an Enbridge gathering system in the province of Saskatchewan, Canada. Most deliveries are made at Clearbrook 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 an aggregate working capacity of approximately 84,000 barrels per day. The North Dakota system also has 16 pump stations and 12 terminaling facilities with an aggregate working storage capacity of approximately 700,000 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 fields served by the North Dakota system have alternative gathering facilities available to them or have the ability to build their own facilities.

Gathering and Processing Segment

        The Partnership owns and operates natural gas gathering, treating and processing systems. These systems purchase and/or gather natural gas from the wellhead, deliver it to plants for treating and/or processing and to intrastate or interstate pipelines for transmission or 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 transportation on transmission pipelines. 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.

        Most of the natural gas gathering, treating and processing assets are located in Texas, with additional facilities in Oklahoma, Mississippi, Louisiana, Kansas and Alabama. The major facilities are listed in the following table:

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        In total, the Partnership has over 6,200 miles of gathering pipelines, 9 active treating plants and 12 active processing plants. The active treating and processing capacities are currently over 700 MMcf/d and 600 MMcf/d respectively.

        The Northeast Texas system is capable of handling sour gas, which has a high hydrogen sulfide and/or carbon dioxide and water content and which requires specialized treating processes before it can be delivered for transportation on downstream pipelines. These treating plants are capable of producing approximately 1,100 long tons of sulfur per day.

        The Partnership acquired the North Texas system on December 31, 2003, for approximately $249.7 million, which also includes the buyout of a capital lease of $1.9 million and transaction costs of $1.8 million. Three of the processing plants receive natural gas primarily from a conglomerate formation in the Fort Worth Basin. A fourth plant receives gas from both the conglomerate and Barnett Shale formations in the Fort Worth Basin. The fifth active processing plant processes gas on a third party pipeline under a combination of a fee-for-service and a products-sharing arrangement with that third party pipeline. The system also includes two pipeline systems that gather lean gas in the Barnett Shale region for a fixed gathering fee. The larger of these two pipelines commenced operation in 2001 and has been growing rapidly with the expansion of the Barnett Shale production. Volume data for 2003, noted in the table above, is derived from the records of the prior owner.

        Customers.    Customers of the Partnership's gathering, treating and processing systems include both natural gas purchasers and producers. Purchasers include marketers and large users of natural gas, such as power plants, industrial facilities and local distribution companies. Producers served by the Partnership's systems consist of small, medium and large independent operators and large integrated energy companies. The Partnership sells NGLs resulting from its processing activities to a variety of customers ranging from large petrochemical and refining companies to small regional retail propane distributors.

        Supply and Demand.    Supply for the Partnership's gathering, treating and processing services primarily depends upon the rate of depletion of natural gas reserves and the drilling rate of new wells. Treating services also are affected by the level of impurities in the natural gas gathered. Demand for these services depends upon overall economic conditions and the prices of natural gas and NGLs. Three of the Partnership's larger systems are located in basins that have experienced recent growth in natural gas land purchases, drilling and production.

        The East Texas system is primarily located in the East Texas Basin. While production from most regions within this basin have remained flat for several years, the Bossier trend within the East Texas Basin has experienced substantial growth. The Bossier trend is located on the western side of the East Texas system. Bossier production has grown from under 200 MMcf/d in 1997 to over 800 MMcf/d in 2003.

        A substantial portion of natural gas on the North Texas system is produced in the Barnett Shale within the Fort Worth Basin Comglomerate. The Fort Worth Basin Conglomerate is a mature zone that is experiencing slow decline. In contrast, the Barnett Shale 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 since the early 1980s, recent technological development in fracturing the shale formation allows commercial production of this gas. Barnett Shale production has risen from 180 MMcf/d to 750 MMcf/d since 2000 with the drilling of over 2,000 wells. Growth in this region is expected for at least ten years.

        The Anadarko system is located within the Anadarko Basin. Within that basin, recent growth is occurring in the Granite Wash play, particularly in Hemphill County, Texas.

        The Partnership intends to expand its natural gas gathering and processing services through a combination of internal growth and acquisitions, which should provide exposure to incremental supplies

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of natural gas at the wellhead, increase opportunities to serve additional customers and allow expansion of the treating and processing businesses.

        Competition.    Competitors of the Partnership's gathering, treating and processing systems include interstate and intrastate pipelines or their affiliates and other natural gas gatherers that gather, treat, process and market natural gas or NGLs. Some of these competitors are substantially larger than the Partnership. Competition for these services 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 the Partnership's Northeast 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.

Trucking Operations

        Also included in the Partnership's Gathering and Processing segment are its trucking operations. Trucking operations include the transportation of NGLs, crude oil and carbon dioxide by truck and railcar from wellheads to treating, processing and fractionation facilities and to wholesale customers, such as distributors, refiners and chemical facilities. In addition, the trucking operations market these products. These services are provided using 105 trucks and trailers and 48 rail cars, product treating and handling equipment and over 400,000 gallons of NGL storage facilities. In addition, a CO₂ plant with 250 tons per day of capacity, takes excess CO₂ from hydrogen producers and sells it to a variety of customers.

        Customers.    Most of the customers of the crude oil and NGL trucking operations are wholesale customers, such as refineries and propane distributors. The trucking operations also market products to wholesale customers such as refineries and petrochemical plants.

        Supply and Demand.    The areas served by the Partnership's trucking operations are geographically diverse, and the forces that affect the supply of the products transported vary by region. The supply of these products is affected by crude oil and natural gas prices and production levels. The demand for trucking operations 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.    The trucking 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 the trucking operations have numerous competitors, including marketers of all types and sizes, affiliates of pipelines and independent aggregators.

Natural Gas Transportation Segment

        Included in this segment are the following major systems that were acquired in connection with the Midcoast system acquisition in October 2002:

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the KPC Pipeline, MidLa Pipeline, AlaTenn Pipeline, and UTOS Pipeline systems, which are FERC regulated natural gas interstate transmission pipelines; and

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the Bamagas Pipeline, Mid-Louisiana Gas Transmission Pipeline and Magnolia Pipeline systems, which are natural gas intrastate transmission pipelines.

        Each of these pipeline systems typically consists of a natural gas transmission pipeline as well as various interconnects to other pipelines that serve wholesale customers.

        Customers.    The Partnership's natural gas transportation pipelines serve customers in Alabama, Kansas, Louisiana, Mississippi, Missouri and Tennessee. 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.

        Supply and Demand.    As the Partnership's natural gas transportation pipelines generally serve different geographical areas, supply and demand vary in each market.

        The Partnership believes that demand for natural gas in the areas served by its natural gas transportation assets generally will remain strong as a result of being located in areas where industrial, commercial or residential growth is occurring. The greatest demand for natural gas transmission services in the markets served by these assets occurs in the winter months.

        The table below indicates the capacity in million cubic feet per day of the transmission and wholesale customer pipelines with firm transportation contracts as of December 31, 2003 and the amount of capacity that is reserved under those contracts as of that date.

        The UTOS system is a FERC-regulated offshore pipeline system with a capacity of 1.2 billion cubic feet of natural gas per day that transmits natural gas from offshore platforms to other pipelines onshore for further delivery. The UTOS system's average daily throughput during 2003 was 209,000 MMBtu/d. The FERC has approved the Partnership's negotiated settlement with UTOS shippers, keeping the current rates in effect through 2006.

        The 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. The Bamagas system in northern Alabama serves two power plants. This system is contiguous with the AlaTenn system and a third party pipeline, allowing for operational flexibility as natural gas could flow between Bamagas and either of the other two systems. The Partnership markets 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. The AlaTenn system had contracts representing 21% of its capacity that terminated in 2003. Expiration of the AlaTenn contracts did not have a material impact on the business segment. As of December 31, 2003, approximately 62% of the capacity of the MidLa system is under contract to affiliated entities.

        The KPC system has 82% of its capacity reserved under firm transportation contracts extending through 2009 and an additional 12% of its capacity reserved under contracts extending through 2017. The KPC system's primary customers are local distribution companies.

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        The Partnership's long-term financial condition depends on the continued availability of natural gas for transportation to the markets served by its 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 served by the Partnership was to render the delivered cost of natural gas uneconomical. The Partnership may be unable to find additional customers to replace the lost demand or transportation fees.

        Competition.    Because pipelines are generally the only practical mode of transportation for natural gas over land, the most significant competitors of the Partnership's natural gas transportation pipelines are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability. Many of the large wholesale customers served by the Partnership 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.

Marketing Segment

        The natural gas Marketing segment provides natural gas supply, transportation, balancing and sales services to producers and wholesale customers on the Partnership's gathering, transmission and wholesale customer pipelines, as well as interconnected third-party pipelines. In general, the Marketing segment makes natural gas purchases from the Partnership's gathering systems and from other producers and marketers. It then makes natural gas sales to wholesale customers on the Partnership's transmission and wholesale customer pipelines. The Marketing segment also arranges transportation for wholesale customers, provides storage services, and contracts capacity on certain third-party pipeline systems.

        Natural gas purchased and sold by the Marketing segment is typically priced based upon a published daily or monthly price index. Sales to wholesale customers incorporate a pass-through charge for costs of transportation and generally include an additional margin.

        The 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.

RISK FACTORS

        The following risk factors should be read in conjunction with the other sections in this Report on Form 10-K.

Transportation Volumes

        The Partnership's financial performance depends to a large extent on the volume of products transported on its pipeline systems. Decreases in the volume of products transported by the Partnership's systems, whether caused by supply and demand factors in the markets these systems serve, or otherwise, can directly and adversely affect the Partnership's revenues and results of operations. See "Business Segments—Liquids Transportation Segment—Lakehead system—Supply and Demand";—"Business Segments—Gathering and Processing Segment—Supply and Demand"; and "Business Segments—Natural Gas Transportation Segment—Supply and Demand".

Regulation

        The tariff rates charged by several of the Partnership's systems are regulated by the FERC or various state regulatory agencies. If the Partnership's tariffs are reduced by one of these regulatory

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agencies on its own initiative or as a result of challenges by third parties, the profitability of the Partnership's pipeline businesses may suffer. If the Partnership is permitted to raise its tariffs for a particular pipeline, there may be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect. Furthermore, competition from other pipeline systems may prevent the Partnership from raising its tariff rates even if regulatory agencies permit the Partnership to do so. The regulatory agencies that regulate the Partnership's systems periodically propose and implement new rules and regulations, terms and conditions of services and rates subject to their jurisdiction. New initiatives or orders may adversely affect the tariff rates charged for services by the Partnership. Several states, including Oklahoma and Texas, are taking a more active role in the rate and service regulation of intrastate natural gas systems. Increased state regulation could adversely impact the Partnership's natural gas systems.

Competition with Enbridge

        Enbridge has agreed with the Partnership that, so long as an affiliate of Enbridge is the general partner of the Partnership, Enbridge and its subsidiaries may not engage in or acquire any business that is in direct material competition with the businesses of the Partnership, subject to the following exceptions:

•

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



•

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



•

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



•

Enbridge and its subsidiaries are not prohibited from acquiring any competitive business if that business is first offered for acquisition to the Partnership and the Partnership fails to approve, after submission to a vote of unitholders, the making of the acquisition.

        As the Partnership was not engaged in any aspect of the natural gas business at the time of its initial public offering, Enbridge and its subsidiaries are not restricted from competing with the Partnership in any aspects 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 the Lakehead system even if such transportation is in direct material competition with the business of the Partnership.

        This agreement 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 the Partnership to supply crude oil to the Ontario, Canada market. This competition from Enbridge has reduced the Partnership's deliveries of crude oil to Ontario.

Market Risk

        As part of its natural gas marketing activities, the Partnership purchases natural gas at prevailing market prices. Following the purchase of natural gas, the Partnership generally resells it at a higher price under a sales contract that has comparable terms to the purchase contract, including any price

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escalation provisions. The profitability of the Partnership's natural gas operations may be affected by the following factors:

•

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



•

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



•

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



•

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



•

the ability of its customers to make timely payment, customer default, and concentration of receivables with third parties in the energy sector.

Environmental and Safety Regulations

        The Partnership's pipeline, gathering, processing and trucking operations are subject to federal and state laws and regulations relating to environmental protection and operational safety. Liquid petroleum and natural gas transportation and processing operations always involve the risk of costs or liabilities related to environmental protection and operational safety matters. It is also possible that the Partnership will have to pay amounts in the future because of changes in environmental and safety laws or enforcement policies or claims for environmentally related damage to persons or property. The Partnership may not be able to recover these costs from insurance, higher fees or through higher pipeline tariffs rates.

Kyoto Protocol

        In December 2002, Canada ratified the Kyoto Protocol, a 1997 treaty designed to reduce greenhouse gas emissions to 6% below 1990 levels. The Partnership and Enbridge are assessing and evaluating the Canadian federal government's approach to implementation. Until these plans become certain, the Partnership will not be able to quantify the impact, if any, of the Kyoto Protocol on its operations. The Partnership is encouraged by reactions by western Canadian crude oil producers to Kyoto, particularly their commitment to oil sands development, which supports the outlook for the sustainability of crude oil supplies for the Lakehead system.

Transportation of Hazardous Materials

        Operation of complex liquid petroleum and natural gas transportation and processing systems involve risks, hazards and uncertainties, such as operational hazards and unforeseen interruptions caused by events beyond the control of the Partnership. For example, the East Texas, Northeast Texas and South Texas systems, and some facilities in Mississippi, handle or transport large quantities of natural gas containing hydrogen sulfide, a highly toxic substance when workers or the public are exposed above safe limits. Some of these pipelines are located in or near densely populated areas. A major release of natural gas containing hydrogen sulfide from one of these pipelines or plants could result in severe injuries or death, as well as severe environmental damage. Insurance proceeds may not be adequate to cover all liabilities incurred or lost revenues.

Growth Strategy

        The acquisition of complementary energy delivery assets is a focus of the Partnership's strategic plan. Acquisitions may present various risks and challenges, including the risks of incorrect assumptions in the acquisition models, effective integration of the acquired operations and diversion of management's attention from existing operations. In addition, the Partnership may be unable to identify

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

Oil Measurement Losses

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

•

physical losses, which occur through evaporation, shrinkage, differences in measurement between receipt and delivery locations and other operational incidents;



•

degradation losses, which result from mixing at the interface between higher quality light crude oil and lower quality heavy crude oil in pipelines; and



•

revaluation losses, which are a function of crude oil prices, the level of the carrier's inventory and the inventory positions of customers.

        There are inherent difficulties in quantifying oil measurement losses because physical measurements of volumes are not practical, as products continuously move through the Partnership's pipelines and virtually all of these pipelines are located underground. Quantifying oil measurement losses is especially difficult for the Partnership because of the length of the Lakehead system and the number of different grades of crude oil and types of crude oil products it carries. The Partnership utilizes engineering-based models and operational assumptions to estimate product volumes in its system and associated oil measurement losses. If there is a material change in these assumptions, it may result in a revision of oil measurement loss estimates.

Conflicts of Interest

        Enbridge indirectly owns all of the stock of the general partner of the Partnership and elects all of its directors. Furthermore, some of the Partnership's directors and officers are also directors and officers of Enbridge. Consequently, conflicts of interest could arise between the Partnership's unitholders and Enbridge.

        The Partnership's partnership agreement limits the fiduciary duties of the general partner of the Partnership to the Partnership's unitholders. These restrictions allow the general partner of the Partnership to resolve conflicts of interest by considering the interests of all the parties to the conflict, including Enbridge Management's interests, the interests of the Partnership and the General Partner. Additionally, these limitations reduce the rights of the Partnership's unitholders under the Partnership's partnership agreement to sue the general partner of the Partnership 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.

State Tax Legislation

        State tax legislation resulting in the imposition of a partnership-level income tax on the Partnership could reduce the cash distributions on the common units and the value of the i-units that the Partnership will distribute quarterly to Enbridge Management. Currently, state-level income taxation of the Partnership is not significant. However, many states have considered increasing their taxes, including some partnership-level taxes, in their recent legislative processes. The enactment of significant legislation imposing partnership-level income taxes would cause a reduction in the value of the partnership units.

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TITLE TO PROPERTIES

        The Partnership currently conducts business and owns properties located in 20 states: Alabama, Arkansas, Florida, Georgia, Illinois, Indiana, Kansas, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, New York, North Carolina, North Dakota, Oklahoma, Texas, Tennessee and Wisconsin. In general, the Partnership's 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 these systems are located on land that is owned by the Partnership, except for five pumping stations that are situated on land owned by others and used by the Partnership under easements or permits.

        Substantially all of the Lakehead system assets are subject to a first mortgage securing indebtedness of the Lakehead Partnership, a principal operating subsidiary of the Partnership.

        In connection with the acquisition of the Midcoast system, certain filings with respect to title records were not made prior to the closing of the transaction. The Partnership or its subsidiaries have now made these filings. Although title to these properties is subject to encumbrances in some cases, the Partnership believes that none of these burdens should materially detract from the value of these properties or materially interfere with their use in the operation of the Partnership's business.

REGULATION

Regulation by the FERC of Interstate Common Carrier Liquids Pipelines

        The Lakehead and North Dakota systems are interstate common carrier liquids pipelines subject to regulation by the FERC under the ICA. As interstate common carriers, 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 requires the Partnership to maintain tariffs on file with the FERC that set forth the rates it charges for providing transportation services on its 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 the Partnership charges for service on its interstate common carrier pipelines. The ICA requires, among other things, that such rates be "just and reasonable" and nondiscriminatory. The ICA permits interested persons to challenge new or proposed changes to existing rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to order a hearing concerning such rates. 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 the revenues in excess of the prior tariff during the term of the investigation. 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, which deemed petroleum pipeline rates that were in effect for the 365-day period ending on the date of enactment and had not been subject to complaint, protest or investigation, to be just and reasonable under the ICA (i.e., "grandfathered"). The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party would have to show that it was previously contractually barred from challenging the rates or that the economic circumstances or the nature of service underlying the rate had substantially changed or that the rate was unduly discriminatory or preferential. These grandfathering provisions and the circumstances under which they may be challenged have received only limited attention from the

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FERC, causing a degree of uncertainty as to their application and scope. The North Dakota system is largely covered by the grandfathering provisions of the Energy Policy Act. The Lakehead system is not covered by the grandfathering provisions of the Energy Policy Act.

        The Energy Policy 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. A pipeline may not be required to reduce its rate below the level grandfathered under the Energy Policy Act. Under Order No. 561, a pipeline must, as a general rule, utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates and settlement as alternatives to the indexing approach, which alternatives may be used in certain specified circumstances.

        The Partnership believes that the rates charged for transportation services on its interstate common carrier liquids pipelines are just and reasonable under the ICA. However, because the rates that the Partnership charges are subject to review upon an appropriately supported complaint, the Partnership cannot predict what rates it will be allowed to charge in the future for service on its interstate common carrier liquids pipelines. Furthermore, because rates charged for transportation services must be competitive with those charged by other transporters, the